10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

þQUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2014

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 June 30, 2014
The Southern Company	Par Value $5 Per Share	895,696,608
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	5,442,717
Mississippi Power Company	Without Par Value	1,121,000
Southern Power Company	Par Value $0.01 Per Share	1,000

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

2

INDEX TO QUARTERLY REPORT ON FORM 10-Q

June 30, 2014

		Page Number
DEFINITIONS		4
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION		6
	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	9
	Condensed Consolidated Statements of Comprehensive Income	10
	Condensed Consolidated Statements of Cash Flows	11
	Condensed Consolidated Balance Sheets	12
	Management's Discussion and Analysis of Financial Condition and Results of Operations	14
	Alabama Power Company
	Condensed Statements of Income	36
	Condensed Statements of Comprehensive Income	36
	Condensed Statements of Cash Flows	37
	Condensed Balance Sheets	38
	Management's Discussion and Analysis of Financial Condition and Results of Operations	40
	Georgia Power Company
	Condensed Statements of Income	53
	Condensed Statements of Comprehensive Income	53
	Condensed Statements of Cash Flows	54
	Condensed Balance Sheets	55
	Management's Discussion and Analysis of Financial Condition and Results of Operations	57
	Gulf Power Company
	Condensed Statements of Income	74
	Condensed Statements of Comprehensive Income	74
	Condensed Statements of Cash Flows	75
	Condensed Balance Sheets	76
	Management's Discussion and Analysis of Financial Condition and Results of Operations	78
	Mississippi Power Company
	Condensed Statements of Operations	92
	Condensed Statements of Comprehensive Income (Loss)	92
	Condensed Statements of Cash Flows	93
	Condensed Balance Sheets	94
	Management's Discussion and Analysis of Financial Condition and Results of Operations	96
	Southern Power Company and Subsidiary Companies
	Condensed Consolidated Statements of Income	120
	Condensed Consolidated Statements of Comprehensive Income	120
	Condensed Consolidated Statements of Cash Flows	121
	Condensed Consolidated Balance Sheets	122
	Management's Discussion and Analysis of Financial Condition and Results of Operations	124
	Notes to the Condensed Financial Statements	133
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	34
Item 4.	Controls and Procedures	34

		Page Number
	PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	172
Item 1A.	Risk Factors	172
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	Inapplicable
Item 3.	Defaults Upon Senior Securities	Inapplicable
Item 4.	Mine Safety Disclosures	Inapplicable
Item 5.	Other Information	Inapplicable
Item 6.	Exhibits	172
	Signatures	175

3

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
2013 IRP	Georgia Power's triennial Integrated Resource Plan as approved by the Georgia PSC
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
Chancery Court	Chancery Court of Harrison County, Mississippi
Clean Air Act	Clean Air Act Amendments of 1990
Contractor	Westinghouse and Stone & Webster, Inc.
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, 2013
GAAP	Generally accepted accounting principles
Georgia Power	Georgia Power Company
GHG	Greenhouse gas
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
ITCs	Investment tax credits
Kemper IGCC	IGCC facility under construction in Kemper County, Mississippi
KWH	Kilowatt-hour
LIBOR	London Interbank Offered Rate
Mississippi Power	Mississippi Power Company
mmBtu	Million British thermal unit
Moody's	Moody's Investors Service, Inc.
MW	Megawatt
NCCR	Nuclear Construction Cost Recovery
NRC	U.S. Nuclear Regulatory Commission
OCI	Other comprehensive income
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
PEP	Mississippi Power's Performance Evaluation Plan

4

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 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 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
ROE	Return on equity
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, and other subsidiaries
Southern Nuclear	Southern Nuclear Operating Company, Inc.
Southern Power	Southern Power Company and its subsidiaries
S&P	Standard and Poor's Ratings Services, a division of The McGraw Hill Companies, Inc.
traditional operating companies	Alabama Power, Georgia Power, Gulf Power, and Mississippi Power
Westinghouse	Westinghouse Electric Company LLC
wholesale revenues	revenues generated from sales for resale

5

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 plans, and nuclear decommissioning trust fund contributions, financing activities, completion dates of construction projects, plans and estimated costs for new generation resources, filings with state and federal regulatory authorities, impact of the American Taxpayer Relief Act of 2012, estimated sales and purchases under power sale and purchase agreements, and estimated construction and other capital 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, coal combustion residuals, and emissions of sulfur, nitrogen, carbon, 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 the 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 recent recession, population and business growth (and declines), the effects of energy conservation 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;

• 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 factors, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under construction or other agreements, operational performance, operational readiness, unforeseen engineering or design problems, delays associated with start-up activities (including major equipment failure and system integration), and/or operations;

• ability to construct facilities in accordance with the requirements of permits and licenses, to satisfy any operational and environmental performance standards, including any PSC requirements 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 litigation proceedings involving the Owners and the Contractor;

• actions related to cost recovery for the Kemper IGCC, including actions relating to proposed securitization, Mississippi PSC approval of Mississippi Power's proposed rate recovery plan, as ultimately amended, which currently includes 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 2014, and satisfaction of requirements to utilize ITCs and grants;

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

• the outcome of any legal or regulatory proceedings regarding the Mississippi PSC's issuance of the CPCN for the Kemper IGCC, the settlement agreement between Mississippi Power and the Mississippi PSC, the March 2013 rate order approving retail rate increases consistent with the terms of the settlement agreement, or the Baseload Act;

6

• 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 terrorist incidents and the threat of terrorist incidents, including cyber intrusion;

• interest rate fluctuations and financial market conditions and the results of financing efforts, including Southern Company's and its subsidiaries' credit ratings;

• the impacts of any potential U.S. credit rating downgrade or other 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 and its subsidiaries to obtain additional generating capacity at competitive prices;

• catastrophic events such as fires, earthquakes, explosions, floods, hurricanes, 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.

7

THE SOUTHERN COMPANY

AND SUBSIDIARY COMPANIES

8

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2014			2013			2014			2013
	(in millions)						(in millions)
Operating Revenues:
Retail revenues	$	3,770		$	3,620		$	7,628		$	6,918
Wholesale revenues	515			454			1,119			886
Other electric revenues	169			156			334			311
Other revenues	13			16			30			28
Total operating revenues	4,467			4,246			9,111			8,143
Operating Expenses:
Fuel	1,462			1,374			3,109			2,636
Purchased power	133			127			320			222
Other operations and maintenance	1,019			947			2,005			1,921
Depreciation and amortization	504			476			1,001			942
Taxes other than income taxes	246			232			493			467
Estimated loss on Kemper IGCC	—			450			380			990
Total operating expenses	3,364			3,606			7,308			7,178
Operating Income	1,103			640			1,803			965
Other Income and (Expense):
Allowance for equity funds used during construction	62			45			119			86
Interest expense, net of amounts capitalized	(210		)	(215		)	(416		)	(426		)
Other income (expense), net	(6		)	1			(13		)	(26		)
Total other income and (expense)	(154		)	(169		)	(310		)	(366		)
Earnings Before Income Taxes	949			471			1,493			599
Income taxes	321			158			497			189
Consolidated Net Income	628			313			996			410
Dividends on Preferred and Preference Stock of Subsidiaries	17			16			34			32
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries	$	611		$	297		$	962		$	378
Common Stock Data:
Earnings per share (EPS) -
Basic EPS	$	0.68		$	0.34		$	1.08		$	0.43
Diluted EPS	$	0.68		$	0.34		$	1.07		$	0.43
Average number of shares of common stock outstanding (in millions)
Basic	895			874			892			872
Diluted	899			879			896			877
Cash dividends paid per share of common stock	$	0.5250		$	0.5075		$	1.0325		$	0.9975

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

9

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2014			2013			2014			2013
	(in millions)						(in millions)
Consolidated Net Income	$	628		$	313		$	996		$	410
Other comprehensive income (loss):
Qualifying hedges:
Reclassification adjustment for amounts included in net income, net of tax of $-, $2, $2 and $4, respectively	1			3			2			6
Pension and other post retirement benefit plans:
Reclassification adjustment for amounts included in net income, net of tax of $1, $1, $1 and $2, respectively	1			2			2			3
Total other comprehensive income (loss)	2			5			4			9
Dividends on preferred and preference stock of subsidiaries	(17		)	(16		)	(34		)	(32		)
Comprehensive Income	$	613		$	302		$	966		$	387

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

10

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Six Months Ended June 30,
	2014			2013
	(in millions)
Operating Activities:
Consolidated net income	$	996		$	410
Adjustments to reconcile consolidated net income to net cash provided from operating activities —
Depreciation and amortization, total	1,182			1,140
Deferred income taxes	46			(141		)
Allowance for equity funds used during construction	(119		)	(86		)
Stock based compensation expense	40			37
Estimated loss on Kemper IGCC	380			990
Other, net	22			48
Changes in certain current assets and liabilities —
-Receivables	(579		)	(325		)
-Fossil fuel stock	419			185
-Materials and supplies	(20		)	52
-Other current assets	(88		)	(55		)
-Accounts payable	(231		)	(52		)
-Accrued taxes	72			6
-Accrued compensation	(40		)	(257		)
-Other current liabilities	(10		)	(5		)
Net cash provided from operating activities	2,070			1,947
Investing Activities:
Property additions	(2,692		)	(2,597		)
Investment in restricted cash	—			(98		)
Distribution of restricted cash	11			23
Nuclear decommissioning trust fund purchases	(445		)	(548		)
Nuclear decommissioning trust fund sales	443			546
Cost of removal, net of salvage	(54		)	(56		)
Change in construction payables, net	89			114
Prepaid long-term service agreement	(93		)	(57		)
Other investing activities	(28		)	44
Net cash used for investing activities	(2,769		)	(2,629		)
Financing Activities:
Increase in notes payable, net	339			767
Proceeds —
Long-term debt issuances	1,314			1,197
Interest-bearing refundable deposit related to asset sale	75			—
Preference stock	—			50
Common stock issuances	318			161
Redemptions —
Long-term debt	(431		)	(792		)
Common stock repurchased	(5		)	(18		)
Payment of common stock dividends	(920		)	(870		)
Payment of dividends on preferred and preference stock of subsidiaries	(34		)	(32		)
Other financing activities	(33		)	15
Net cash provided from financing activities	623			478
Net Change in Cash and Cash Equivalents	(76		)	(204		)
Cash and Cash Equivalents at Beginning of Period	659			628
Cash and Cash Equivalents at End of Period	$	583		$	424
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $47 and $37 capitalized for 2014 and 2013, respectively)	$	365		$	384
Income taxes, net	212			142
Noncash transactions — accrued property additions at end of period	509			637

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

11

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

Assets	At June 30, 2014			At December 31, 2013
	(in millions)
Current Assets:
Cash and cash equivalents	$	583		$	659
Receivables —
Customer accounts receivable	1,237			1,027
Unbilled revenues	532			448
Under recovered regulatory clause revenues	86			58
Other accounts and notes receivable	281			304
Accumulated provision for uncollectible accounts	(17		)	(18		)
Fossil fuel stock, at average cost	920			1,339
Materials and supplies, at average cost	981			959
Vacation pay	171			171
Prepaid expenses	422			489
Other regulatory assets, current	117			124
Other current assets	63			39
Total current assets	5,376			5,599
Property, Plant, and Equipment:
In service	67,235			66,021
Less accumulated depreciation	23,492			23,059
Plant in service, net of depreciation	43,743			42,962
Other utility plant, net	226			240
Nuclear fuel, at amortized cost	868			855
Construction work in progress	7,927			7,151
Total property, plant, and equipment	52,764			51,208
Other Property and Investments:
Nuclear decommissioning trusts, at fair value	1,531			1,465
Leveraged leases	675			665
Miscellaneous property and investments	230			218
Total other property and investments	2,436			2,348
Deferred Charges and Other Assets:
Deferred charges related to income taxes	1,467			1,432
Prepaid pension costs	431			419
Unamortized debt issuance expense	200			139
Unamortized loss on reacquired debt	281			293
Other regulatory assets, deferred	2,642			2,557
Other deferred charges and assets	803			551
Total deferred charges and other assets	5,824			5,391
Total Assets	$	66,400		$	64,546

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

12

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholders' Equity	At June 30, 2014			At December 31, 2013
	(in millions)
Current Liabilities:
Securities due within one year	$	585		$	469
Interest-bearing refundable deposit related to asset sale	225			150
Notes payable	1,817			1,482
Accounts payable	1,320			1,376
Customer deposits	386			380
Accrued taxes —
Accrued income taxes	58			13
Other accrued taxes	391			456
Accrued interest	268			251
Accrued vacation pay	213			217
Accrued compensation	282			303
Other regulatory liabilities, current	92			92
Other current liabilities	337			347
Total current liabilities	5,974			5,536
Long-term Debt	22,121			21,344
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	10,644			10,563
Deferred credits related to income taxes	194			202
Accumulated deferred investment tax credits	1,014			966
Employee benefit obligations	1,428			1,461
Asset retirement obligations	2,026			2,006
Other cost of removal obligations	1,332			1,270
Other regulatory liabilities, deferred	537			475
Other deferred credits and liabilities	573			584
Total deferred credits and other liabilities	17,748			17,527
Total Liabilities	45,843			44,407
Redeemable Preferred Stock of Subsidiaries	375			375
Stockholders' Equity:
Common Stockholders' Equity:
Common stock, par value $5 per share —
Authorized — 1.5 billion shares
Issued — June 30, 2014: 897 million shares
— December 31, 2013: 893 million shares
Treasury — June 30, 2014: 0.9 million shares
— December 31, 2013: 5.7 million shares
Par value	4,480			4,461
Paid-in capital	5,499			5,362
Treasury, at cost	(35		)	(250		)
Retained earnings	9,553			9,510
Accumulated other comprehensive loss	(71		)	(75		)
Total Common Stockholders' Equity	19,426			19,008
Preferred and Preference Stock of Subsidiaries	756			756
Total Stockholders' Equity	20,182			19,764
Total Liabilities and Stockholders' Equity	$	66,400		$	64,546

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

13

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

SECOND QUARTER 2014 vs. SECOND QUARTER 2013

AND

YEAR-TO-DATE 2014 vs. YEAR-TO-DATE 2013

OVERVIEW

Southern Company is a holding company that owns all of the common stock of the traditional operating companies – Alabama Power, Georgia Power, Gulf Power, and Mississippi Power – and Southern Power and 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 (45.7% ownership interest by Georgia Power in two units, each with approximately 1,100 MWs) and the Kemper IGCC (in which Mississippi Power is ultimately expected to hold an 85% ownership interest in the 582-MW facility). 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. See Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for information regarding the revision to the cost estimate for the Kemper IGCC that has negatively impacted Southern Company's earnings per share, one of its key performance indicators, for 2014, as compared to the target.

RESULTS OF OPERATIONS

Net Income

Second Quarter 2014 vs. Second Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$314	105.7	$584	154.5

Southern Company's second quarter 2014 net income after dividends on preferred and preference stock of subsidiaries was $611 million ($0.68 per share) compared to $297 million ($0.34 per share) for the second quarter 2013. The increase was primarily the result of a $450 million pre-tax charge ($278 million after tax) recorded in the second quarter 2013 with respect to a revision of the estimated costs expected to be incurred on Mississippi Power's construction of the Kemper IGCC. In addition, the increase was related to an increase in revenues due to warmer weather in the second quarter 2014 compared to the corresponding period in 2013 as well as retail base rate increases, partially offset by increases in non-fuel operations and maintenance expenses.

Southern Company's year-to-date 2014 net income after dividends on preferred and preference stock of subsidiaries was $962 million ($1.08 per share) compared to $378 million ($0.43 per share) for the corresponding period in 2013. The increase was primarily the result of a $380 million pre-tax charge ($235 million after tax) recorded in the first quarter 2014 compared to $990 million in pre-tax charges ($611 million after tax) in the first half of 2013 for

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

revisions of estimated costs expected to be incurred on Mississippi Power's construction of the Kemper IGCC. The increase was also related to an increase in revenues due to colder weather in the first quarter 2014 and warmer weather in the second quarter 2014 compared to the corresponding periods in 2013 as well as retail base rate increases, partially offset by increases in non-fuel operations and maintenance expenses.

Retail Revenues

Second Quarter 2014 vs. Second Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$150	4.1	$710	10.3

In the second quarter 2014, retail revenues were $3.8 billion compared to $3.6 billion for the corresponding period in 2013. For year-to-date 2014, retail revenues were $7.6 billion compared to $6.9 billion for the corresponding period in 2013.

Details of the changes in retail revenues were as follows:

	Second Quarter 2014				Year-to-Date 2014
	(in millions)		(% change)		(in millions)		(% change)
Retail – prior year	$	3,620			$	6,918
Estimated change resulting from –
Rates and pricing	68		1.9		152		2.2
Sales growth	7		0.2		21		0.3
Weather	34		0.9		151		2.2
Fuel and other cost recovery	41		1.1		386		5.6
Retail – current year	$	3,770	4.1	%	$	7,628	10.3	%

Revenues associated with changes in rates and pricing increased in the second quarter 2014 when compared to the corresponding period in 2013 primarily due to retail rate increases at Alabama Power, Georgia Power, and Gulf Power effective January 1, 2014. The increase in revenues at Georgia Power was primarily due to base tariff increases, as approved by the Georgia PSC in 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. Also contributing to the increase were increased revenues at Alabama Power associated with Rate CNP Environmental primarily resulting from the inclusion of pre-2005 environmental assets and increased revenues at Gulf Power primarily resulting from the retail base rate increase, as approved by the Florida PSC.

Revenues associated with changes in rates and pricing increased year-to-date 2014 when compared to the corresponding period in 2013 primarily due to retail rate increases at all of the traditional operating companies. The increase in revenues at Georgia Power was primarily due to base tariff increases effective January 1, 2014, as approved by the Georgia PSC in 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 as well as higher contributions from market-driven rates from commercial and industrial customers. Also contributing to the increase were increased revenues at Alabama Power associated with Rate CNP Environmental primarily resulting from the inclusion of pre-2005 environmental assets, increased revenues at Mississippi Power related to a PEP base rate increase and the recognition as revenue of a portion of the rate increase related to Kemper IGCC cost recovery, which both became effective March 19, 2013, and increased revenues at Gulf Power primarily resulting from the retail base rate increase effective January 2014, as approved by the Florida PSC.

See Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Georgia Power – Rate Plans," "Retail Regulatory Matters – Alabama Power – Rate CNP," and "Retail Regulatory Matters – Gulf Power – Retail Base Rate Case" in Item 8 of the Form 10-K for additional information. Also see Note (B) to the

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Condensed Financial Statements under "Retail Regulatory Matters – Mississippi Power – Performance Evaluation Plan" and "Integrated Coal Gasification Combined Cycle" herein for additional information.

Revenues attributable to changes in sales increased in the second quarter 2014 when compared to the corresponding period in 2013. The increase was due to a 3.0% increase in industrial KWH sales, partially offset by a 0.6% decrease in weather-adjusted residential KWH sales while weather-adjusted commercial KWH sales remained flat. The increase in industrial KWH sales for the second quarter 2014 was primarily due to increased sales in the chemicals, paper, primary metals, transportation, and stone, clay, and glass sectors. The decrease in weather-adjusted residential KWH sales for the second quarter 2014 was primarily due to decreased customer usage, partially offset by customer growth.

Revenues attributable to changes in sales increased for year-to-date 2014 when compared to the corresponding period in 2013. The increase was due to a 2.9% increase in industrial KWH sales and a 0.3% increase in weather-adjusted residential KWH sales, partially offset by a 0.1% decrease in weather-adjusted commercial KWH sales. The increase in industrial KWH sales for year-to-date 2014 was primarily due to increased sales in the primary metals, chemicals, paper, transportation, and stone, clay, and glass sectors. The increase in weather-adjusted residential KWH sales for year-to-date 2014 was primarily due to customer growth, partially offset by decreased customer usage. The decrease in weather-adjusted commercial KWH sales for year-to-date 2014 was primarily due to decreased customer usage, partially offset by customer growth.

Fuel and other cost recovery revenues increased $41 million in the second quarter 2014 when compared to the corresponding period in 2013 primarily due to increased energy sales. Fuel and other cost recovery revenues increased $386 million for year-to-date 2014 when compared to the corresponding period in 2013 primarily due to higher fuel costs and increased energy sales.

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

Wholesale Revenues

Second Quarter 2014 vs. Second Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$61	13.4	$233	26.3

Wholesale revenues consist of PPAs primarily with investor-owned utilities and electric cooperatives and short-term opportunity sales. Wholesale revenues from 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. Short-term opportunity sales are made at market-based rates that generally provide a margin above the Southern Company system's variable cost to produce the energy.

In the second quarter 2014, wholesale revenues were $515 million compared to $454 million for the corresponding period in 2013 primarily related to a $66 million increase in energy revenues. The increase in energy revenues was primarily related to new solar PPAs and requirements contracts, increased revenue under existing contracts, and an increase in KWH sales resulting from utilization of the Southern Company system's lower cost generation.

For year-to-date 2014, wholesale revenues were $1.12 billion compared to $886 million for the corresponding period in 2013, reflecting a $221 million increase in energy revenues and a $12 million increase in capacity

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

revenues. The increase in energy revenues was primarily related to increased demand resulting from colder weather in the first quarter 2014 compared to the corresponding period in 2013 and an increase in the average cost of natural gas. Also contributing to the increase in energy revenues were increased revenue under existing contracts as well as new solar PPAs and requirements contracts. The increase in capacity revenues was primarily due to wholesale base rate increases at Mississippi Power.

Other Electric Revenues

Second Quarter 2014 vs. Second Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$13	8.3	$23	7.4

In the second quarter 2014, other electric revenues were $169 million compared to $156 million for the corresponding period in 2013. For year-to-date 2014, other electric revenues were $334 million compared to $311 million for the corresponding period in 2013. The increases were primarily due to increases in transmission revenues at Alabama Power and Georgia Power related to the open access transmission tariff and solar application fee revenue at Georgia Power.

Fuel and Purchased Power Expenses

	Second Quarter 2014 vs. Second Quarter 2013			Year-to-Date 2014 vs. Year-to-Date 2013
	(change in millions)		(% change)	(change in millions)		(% change)
Fuel	$	88	6.4	$	473	17.9
Purchased power	6		4.7	98		44.1
Total fuel and purchased power expenses	$	94		$	571

In the second quarter 2014, total fuel and purchased power expenses were $1.6 billion compared to $1.5 billion for the corresponding period in 2013. The increase was primarily the result of a $104 million increase in the volume of KWHs generated primarily due to increased demand resulting from warmer weather in the second quarter 2014 compared to the corresponding period in 2013 and a $49 million increase in the average cost of purchased power, partially offset by a $40 million decrease in the volume of KWHs purchased as the marginal cost of the Southern Company system's generation available was lower than the market cost of available energy and a $19 million decrease in the average cost of fuel.

For year-to-date 2014, total fuel and purchased power expenses were $3.4 billion compared to $2.9 billion for the corresponding period in 2013. The increase was primarily the result of a $313 million increase in the average cost of fuel and purchased power primarily due to higher natural gas prices and a $312 million increase in the volume of KWHs generated primarily due to increased demand resulting from colder weather in the first quarter 2014 and warmer weather in the second quarter 2014 compared to the corresponding periods in 2013. These increases were partially offset by a $54 million decrease in the volume of KWHs purchased as the marginal cost of the Southern Company system's generation available was lower than the market cost of available energy.

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 – "PSC 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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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

	Second Quarter 2014	Second Quarter 2013	Year-to-Date 2014	Year-to-Date 2013
Total generation (billions of KWHs)	47	44	94	86
Total purchased power (billions of KWHs)	2	3	5	6
Sources of generation (percent) —
Coal	44	41	45	37
Nuclear	17	17	16	17
Gas	36	37	35	41
Hydro	3	5	4	5
Cost of fuel, generated (cents per net KWH) —
Coal	3.79	4.06	4.00	4.10
Nuclear	0.89	0.88	0.89	0.86
Gas	3.82	3.56	4.00	3.32
Average cost of fuel, generated (cents per net KWH)	3.28	3.30	3.46	3.19
Average cost of purchased power (cents per net KWH)(a)	7.41	5.32	8.20	4.98

(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 second quarter 2014, fuel expense was $1.5 billion compared to $1.4 billion for the corresponding period in 2013. The increase was primarily due to a 14.0% increase in the volume of KWHs generated by coal and a 25.2% decrease in the volume of KWHs generated by hydro facilities resulting from less rainfall.

For year-to-date 2014, fuel expense was $3.1 billion compared to $2.6 billion for the corresponding period in 2013. The increase was primarily due to a 31.4% increase in the volume of KWHs generated by coal, a 20.5% increase in the average cost of natural gas per KWH generated, and an 18.4% decrease in the volume of KWHs generated by hydro facilities resulting from less rainfall, partially offset by an 11.4% decrease in the volume of KWHs generated by natural gas.

Purchased Power

In the second quarter 2014, purchased power expense was $133 million compared to $127 million for the corresponding period in 2013. The increase was primarily due to a 39.3% increase in the average cost per KWH purchased, partially offset by a 23.9% decrease in the volume of KWHs purchased as the marginal cost of the Southern Company system's generation available was lower than the market cost of available energy primarily due to higher natural gas prices.

For year-to-date 2014, purchased power expense was $320 million compared to $222 million for the corresponding period in 2013. The increase was primarily due to a 64.7% increase in the average cost per KWH purchased, partially offset by a 17.5% decrease in the volume of KWHs purchased as the marginal cost of the Southern Company system's generation available was lower than the market cost of available energy primarily due to higher natural gas prices.

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

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Other Operations and Maintenance Expenses

Second Quarter 2014 vs. Second Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$72	7.6	$84	4.4

In the second quarter 2014, other operations and maintenance expenses were $1.02 billion compared to $947 million for the corresponding period in 2013. The increase was primarily due to a $30 million increase in scheduled outage and maintenance costs at generation facilities, a $19 million increase in transmission and distribution costs primarily related to overhead line maintenance, a $14 million net increase in employee compensation and benefits including pension, a $9 million increase in commodity and contract labor costs, and a $7 million increase in customer accounts, service, and sales costs primarily related to customer incentive and demand-side management programs. The increase in scheduled outage and maintenance costs was partially offset by a $16 million deferral of certain non-nuclear outage expenditures under an accounting order at Alabama Power.

For year-to-date 2014, other operations and maintenance expenses were $2.0 billion compared to $1.9 billion for the corresponding period in 2013. The increase was primarily due to a $57 million increase in scheduled outage and maintenance costs at generation facilities, a $23 million increase in transmission and distribution costs primarily related to overhead line maintenance, a $23 million increase in commodity and contract labor costs, and a $10 million increase in litigation expense. The increase in scheduled outage and maintenance costs was partially offset by a $41 million deferral of certain non-nuclear outage expenditures under an accounting order at Alabama Power.

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

Second Quarter 2014 vs. Second Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$28	5.9	$59	6.3

In the second quarter 2014, depreciation and amortization was $504 million compared to $476 million for the corresponding period in 2013. For year-to-date 2014, depreciation and amortization was $1.0 billion compared to $942 million for the corresponding period in 2013. The increases were primarily due to an increase in depreciation rates related to environmental assets at Alabama Power, an increase in plant in service at Southern Power related to the additions of Plants Campo Verde and Spectrum in the second half of 2013 as well as equipment retirements resulting from accelerated outage work in 2014, and the completion of amortization related to state income tax credits in December 2013 at Georgia Power. These increases were partially offset by a decrease in depreciation and amortization at Georgia Power, as authorized in the 2013 ARP. The increase for year-to-date 2014 was also partially offset by reductions in depreciation at Gulf Power, as approved by the Florida PSC. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Alabama Power – Rate CNP" of Southern Company in Item 7 of the Form 10-K for additional information regarding Alabama Power's revision to Rate CNP Environmental.

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Taxes Other Than Income Taxes

Second Quarter 2014 vs. Second Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$14	6.0	$26	5.6

In the second quarter 2014, taxes other than income taxes were $246 million compared to $232 million for the corresponding period in 2013. For year-to-date 2014, taxes other than income taxes were $493 million compared to $467 million for the corresponding period in 2013. The increases were primarily the result of an increase in municipal franchise fees related to higher retail revenues in 2014.

Estimated Loss on Kemper IGCC

Second Quarter 2014 vs. Second Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$(450)	(100.0)	$(610)	(61.6)

In the second quarter 2013, an estimated probable loss on the Kemper IGCC of$450 million was recorded at Southern Company. For year-to-date 2014 and 2013, estimated probable losses on the Kemper IGCC of $380 million and $990 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

Second Quarter 2014 vs. Second Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$17	37.8	$33	38.4

In the second quarter 2014, AFUDC equity was $62 million compared to $45 million for the corresponding period in 2013. For year-to-date 2014, AFUDC equity was $119 million compared to $86 million for the corresponding period in 2013. The increases were primarily due to an increase in CWIP related to Mississippi Power's Kemper IGCC. See Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information regarding the Kemper IGCC.

Interest Expense, Net of Amounts Capitalized

Second Quarter 2014 vs. Second Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$(5)	(2.3)	$(10)	(2.3)

In the second quarter 2014, interest expense, net of amounts capitalized was $210 million compared to $215 million in the corresponding period in 2013. For year-to-date 2014, interest expense, net of amounts capitalized was $416 million compared to $426 million in the corresponding period in 2013. The decreases were primarily related to the refinancing of long-term debt at lower rates and capitalized interest at Mississippi Power, partially offset by an

20

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

increase in outstanding long-term debt and an increase in interest expense at Mississippi Power resulting from the SMEPA deposit received in January 2014 related to its pending purchase of an undivided interest in the Kemper IGCC. See Note (E) to the Condensed Financial Statements herein for additional information.

Other Income (Expense), Net

Second Quarter 2014 vs. Second Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$(7)	N/M	$13	50.0

N/M – Not meaningful

In the second quarter 2014, other income (expense), net was $(6) million compared to $1 million for the corresponding period in 2013. The change was primarily due to a decrease in sales of non-utility property at Alabama Power.

For year-to-date 2014, other income (expense), net was $(13) million compared to $(26) million for the corresponding period in 2013. The decrease in expense was primarily due to a $26 million charge related to the restructuring of a leveraged lease investment in the first quarter 2013, partially offset by a decrease in sales of non-utility property at Alabama Power.

Income Taxes

Second Quarter 2014 vs. Second Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$163	103.2	$308	163.0

In the second quarter 2014, income taxes were $321 million compared to $158 million for the corresponding period in 2013. The increase was primarily due to a tax benefit related to the estimated probable loss recorded in 2013 on Mississippi Power's construction of the Kemper IGCC.

For year-to-date 2014, income taxes were $497 million compared to $189 million for the corresponding period in 2013. The increase was primarily due to higher pre-tax earnings and a lower tax benefit related to the estimated probable losses recorded on Mississippi Power's construction of the Kemper IGCC.

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. Another major factor is the profitability of the competitive wholesale business. Future earnings for the electricity business in the near term will depend, in part, upon maintaining and growing sales which is 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 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, 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

21

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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. 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" and – "PSC Matters – Alabama Power – Environmental Accounting Order" of Southern Company in Item 7 of the Form 10-K and "PSC Matters – Alabama Power – Environmental Accounting Order" herein for additional information regarding Alabama Power's plan for compliance with environmental statutes and regulations.

Air Quality

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Air Quality" of Southern Company in Item 7 of the Form 10-K for additional information regarding the Cross State Air Pollution Rule (CSAPR) and the EPA's proposed rules regarding the regulation of excess emissions during periods of startup, shutdown, or malfunction (SSM).

On April 29, 2014, the U.S. Supreme Court overturned the U.S. Court of Appeals for the District of Columbia Circuit's August 2012 decision to vacate CSAPR and remanded the case back to the U.S. Court of Appeals for the District of Columbia Circuit for further proceedings. On June 26, 2014, the EPA requested that the U.S. Court of Appeals for the District of Columbia Circuit lift the stay on CSAPR and approve a revised schedule with compliance to begin on January 1, 2015.

On June 10, 2014, the EPA entered into a revised settlement agreement requiring it to issue a supplemental proposed SSM rule by September 5, 2014 and finalize the proposed rule by May 22, 2015.

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

Water Quality

On April 21, 2014, the EPA and the U.S. Army Corps of Engineers jointly published a proposed rule to revise the regulatory definition of waters of the U.S. for all Clean Water Act (CWA) programs, significantly expanding the scope of federal jurisdiction under the CWA. If finalized as proposed, this rule could significantly increase permitting and regulatory requirements and costs associated with the siting of new facilities and the installation, expansion, and maintenance of transmission and distribution lines. In addition, the rule as proposed could have significant impacts on economic development projects which could affect customer demand growth. The ultimate impact of the proposed rule will depend on the specific requirements of the final rule and the outcome of any legal challenges and cannot be determined at this time.

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Water Quality" of Southern Company in Item 7 of the Form 10-K for additional information regarding the EPA's rulemaking for cooling water intake structures.

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

On May 19, 2014, the EPA signed a final rule establishing standards for reducing effects on fish and other aquatic life caused by new and existing cooling water intake structures at existing power plants and manufacturing facilities. The ultimate outcome of this final rule will depend on the results of additional studies and implementation of the rule by state regulators, but could result in additional capital and operational costs associated with changes to existing intake structures and cooling systems and increased costs associated with the construction of new generating units. The ultimate impact of this rule will depend on the outcome of any legal challenges and cannot be determined at this time.

Global Climate Issues

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues" of Southern Company in Item 7 of the Form 10-K for additional information regarding the EPA's current and proposed regulation of GHG emissions under the Clean Air Act.

On June 18, 2014, the EPA published the proposed Clean Power Plan, setting forth guidelines for states to develop plans to address CO₂ emissions from existing fossil fuel-fired electric generating units. The EPA's proposed guidelines establish state-specific interim and final CO₂ emission rate goals to be achieved between 2020 and 2029 and in 2030 and thereafter. The EPA also published the proposed CO₂ performance standards for modified and reconstructed fossil fuel-fired electric generating units. If finalized as proposed, the proposed guidelines and standards could result in operational restrictions and material compliance costs, including capital expenditures, that could impact unit retirement and replacement decisions. Also, additional compliance costs could affect results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates or through market-based contracts. Further, any resulting higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively impact results of operations, cash flows, and financial condition. The ultimate impact of these proposals will depend on the specific requirements of the final guidelines and performance standards, implementation by states, and the outcome of any legal challenges and cannot be determined at this time.

On June 23, 2014, the U.S. Supreme Court struck down a portion of the EPA's program for GHG permitting under the Prevention of Significant Deterioration and Title V operating permit programs, holding that a facility's GHG emissions alone could not trigger a requirement to obtain a permit and that the EPA did not have the authority to tailor the statutory permitting thresholds. The ultimate impact of this decision cannot be determined at this time.

PSC 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. At June 30, 2014, Georgia Power, Gulf Power, and Mississippi Power had total under recovered fuel costs included on Southern Company's Condensed Balance Sheet herein of approximately $302 million. At December 31, 2013, Gulf Power had under recovered fuel costs included on Southern Company's Condensed Balance Sheet herein of approximately $21 million. The total over recovered fuel balance at Alabama Power included on Southern Company's Condensed Balance Sheet herein was approximately $19 million at June 30, 2014 compared to the total over recovered fuel balance at Alabama Power, Georgia Power, and Mississippi Power at December 31, 2013 of approximately $115 million.

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

Georgia Power's under recovered fuel balance exceeded the $200 million threshold, triggering the Interim Fuel Rider mechanism. Therefore, on July 7, 2014, Georgia Power filed a plan with the Georgia PSC recommending that

23

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

the Georgia PSC defer any action on the under recovered fuel balance until the next fuel case which is expected to be filed by February 27, 2015. The Georgia PSC took no action on Georgia Power's filing within 30 days; therefore, the existing fuel rates remain in place. See Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Fuel Cost Recovery" herein for additional information.

Alabama Power

Environmental Accounting Order

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

As part of its environmental compliance strategy, Alabama Power plans to retire Plant Gorgas Units 6 and 7. These units represent 200 MWs of Alabama Power's approximately 12,200 MWs of generating capacity. Alabama Power also plans to cease 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. Additionally, Alabama Power expects to cease using coal at Plant Barry Unit 3 (225 MWs) and Plant Greene County Units 1 and 2 (300 MWs) and begin operating those units solely on natural gas. These plans are expected to be effective no later than April 2016.

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.

Nuclear Waste Fund Accounting Order

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Other Matters" of Southern Company in Item 7 of the Form 10-K and "Other Matters" herein for additional information regarding the court order for the DOE to set the spent fuel depositary fees at zero.

On August 5, 2014, the Alabama PSC issued an order to provide for the continued recovery from customers of amounts associated with the permanent disposal of nuclear waste from the operation of Plant Farley. In accordance with the order, effective May 16, 2014, Alabama Power is authorized to recover from customers an amount equal to the prior fee and to record the amounts in a regulatory liability account (approximately $14 million annually). Upon the DOE meeting the requirements of the Nuclear Waste Policy Act of 1982 and a new spent fuel depositary fee being put in place, the accumulated balance in the regulatory liability account will be available for purposes of the associated cost responsibility. In the event the balance is later determined to be more than needed, those amounts would be used for the benefit of customers subject to the approval of the Alabama PSC.The ultimate outcome of this matter cannot be determined at this time.

Georgia Power

Renewables Development

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Georgia Power – Renewables Development" of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Georgia Power – Renewables Development" in Item 8 of the Form 10-K for additional information.

On May 20, 2014, the Georgia PSC approved Georgia Power's application for the certification of two PPAs executed in April 2013 for the purchase of energy from two wind farms in Oklahoma with capacity totaling 250 MWs that will begin in 2016 and end in 2035.

As a result of biomass PPA amendments executed by Georgia Power during the second and third quarters of 2014, contractual obligations related to PPAs decreased $491 million from December 31, 2013. Estimated purchased

24

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

power contractual obligations have been updated for Southern Company to $689million for 2015 and 2016, $748 million for 2017 and 2018, and $3.8 billion after 2018. Estimated purchased power contractual obligations did not change for 2014. The counterparties of the aforementioned PPAs have posted collateral as required. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations – Contractual Obligations" of Southern Company in Item 7 of the Form 10-K for additional information.

Integrated Resource Plan

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Georgia Power – Integrated Resource Plans" of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Georgia Power – Integrated Resource Plans" in Item 8 of the Form 10-K for additional information.

Georgia Power filed a request with the Georgia PSC on January 10, 2014 to cancel the proposed biomass fuel conversion of Plant Mitchell Unit 3 (155 MWs) because it would not be cost effective for customers. On July 1, 2014, the Georgia PSC approved Georgia Power's request. The January 10, 2014 filing also notified the Georgia PSC of Georgia Power's plan to seek decertification later this year. Georgia Power now expects to request decertification of Plant Mitchell Unit 3 in connection with the triennial Integrated Resource Plan in 2016. Georgia Power plans to continue to operate the unit as needed until the Mercury and Air Toxics Standards rule becomes effective in April 2015.

Storm Damage Recovery

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Georgia Power – Storm Damage Recovery" of Southern Company in Item 7 of the Form 10-K for additional information.

Georgia Power defers and recovers certain costs related to damages from major storms as mandated by the Georgia PSC. As of June 30, 2014 and December 31, 2013, the balance in the regulatory asset related to storm damage was $107 million and $37 million, respectively. The increase was primarily the result of an ice storm in February 2014. As a result of the regulatory treatment, costs related to storms are generally not expected to have a material impact on Southern Company's financial statements.

Income Tax Matters

Bonus Depreciation

In January 2013, the American Taxpayer Relief Act of 2012 (ATRA) was signed into law. The ATRA retroactively extended several tax credits through 2013 and extended 50% bonus depreciation for property placed in service in 2013 (and for certain long-term production-period projects to be placed in service in 2014), which is currently expected to apply primarily to the combined cycle and associated common facilities portion of the Kemper IGCC. The estimated cash flow benefit of approximately $120 million is dependent upon placing the assets in service in 2014. As discussed in Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein, the remainder of the Kemper IGCC, including the gasification system, would not qualify for bonus depreciation under the ATRA if placed in service after 2014.

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

25

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

approvals 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 (45.7% ownership interest by Georgia Power in two units, each with approximately 1,100 MWs) and the 582-MW Kemper IGCC (in which Mississippi Power is ultimately expected to hold an 85% ownership interest). See FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein for the cost estimate of the Southern Company system's construction program, which includes the current construction cost estimate to complete the Kemper IGCC. Also 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.

From 2013 through June 30, 2014, Southern Company has recorded pre-tax charges totaling $1.56 billion ($963.3 million after tax) for revisions of 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. 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.

Other Matters

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

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 the Notes 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.

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Other Matters" of Southern Company in Item 7 of the Form 10-K for additional information regarding the NRC's performance of additional operational and safety reviews of nuclear facilities in the U.S. following the major earthquake and tsunami that struck Japan in 2011.

Additionally, there are 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 events cannot be determined at this time.

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Other Matters" of Southern Company in Item 7 of the Form 10-K for additional information regarding the court order for the DOE to set the spent fuel depositary fees at zero. On March 18, 2014, the U.S. Court of Appeals for the District of

26

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Columbia Circuit denied the DOE's request for rehearing of the November 2013 panel decision ordering that the DOE propose the nuclear waste fund fee be changed to zero. The DOE formally set the fee to zero effective May 16, 2014. On June 17, 2014, the Georgia PSC approved Georgia Power's request to credit customers the portion of fuel cost related to the nuclear waste fund fee. The nuclear waste fund rider was implemented July 1, 2014. See "PSC Matters – Alabama Power – Nuclear Waste Fund Accounting Order" herein for information regarding an accounting order issued by the Alabama PSC which provides for continued recovery from customers of amounts associated with the permanent disposal of nuclear waste from the operation of Plant Farley. The ultimate outcome of this matter cannot be determined at this time.

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 2014, Mississippi Power further extended the scheduled in-service date for the Kemper IGCC to the second quarter 2015 and 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 related costs 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 $380.0 million ($234.7 million after tax) in the first quarter 2014, $40.0 million ($24.7 million after tax) in the fourth quarter 2013, $150.0 million ($92.6 million after tax) in the third quarter 2013, $450.0 million ($277.9 million after tax) in the second quarter 2013, and $540.0 million ($333.5 million after tax) in the first quarter 2013. In the aggregate, Southern Company has incurred charges of $1.56 billion ($963.3 million after tax) as a result of changes in the cost estimate for the Kemper IGCC through June 30, 2014.

Mississippi Power has experienced, and may continue to experience, material volatility 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, contract or supplier delay, non-performance under construction or other agreements, operational performance, operational readiness, unforeseen engineering or design problems, start-up activities for this first-of-a-kind technology (including major equipment failure and system integration), and/or operations.

Mississippi Power's revised cost estimate includes costs through May 31, 2015. Any further extension of the in-service date is currently estimated to result in additional costs of approximately $20 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.

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

Recently Issued Accounting Standards

On May 28, 2014, the Financial Accounting Standards Board issued ASC 606, Revenue from Contracts with Customers. ASC 606 revises the accounting for revenue recognition and is effective for fiscal years beginning after December 15, 2016. Southern Company is currently evaluating the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined.

FINANCIAL CONDITION AND LIQUIDITY

Overview

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Southern Company in Item 7 of the Form 10-K for additional information. Although earnings for the six months ended June 30, 2014 were negatively affected by revisions to the cost estimate for the Kemper IGCC, Southern Company's financial condition remained stable at June 30, 2014. Through June 30, 2014, Southern Company has incurred non-recoverable cash expenditures of $925 million and is expected to incur approximately $635 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 its bank credit arrangements to meet future capital and liquidity needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.

Net cash provided from operating activities totaled $2.1 billion for the first six months of 2014, an increase of $123 million from the corresponding period in 2013. The increase in net cash provided from operating activities was primarily due to an increase in revenue due to rate increases and the effects of weather and a reduction in fossil fuel stock resulting from an increase in KWH generation, partially offset by a decrease in receivables due to under recovered fuel costs. Net cash used for investing activities totaled $2.8 billion for the first six months of 2014 primarily due to property additions to utility plant. Net cash provided from financing activities totaled $623 million for the first six months of 2014. This was primarily due to issuances of long-term debt and common stock, partially offset by common stock dividend payments. 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 six months of 2014 include an increase of $1.6 billion in total property, plant, and equipment for construction of generation, transmission, and distribution facilities. Other significant changes include a $777 million increase in long-term debt (excluding amounts due within a year) to repay short-term debt and to fund the Southern Company subsidiaries' continuous construction programs, an increase of $335 million in notes payable due to an increase in commercial paper, an increase of $215 million in treasury stock issuances, an increase of $137 million in paid-in capital due to additional common stock issuances, and an increase of $116 million in securities due within one year.

At the end of the second quarter 2014, the market price of Southern Company's common stock was $45.38 per share (based on the closing price as reported on the New York Stock Exchange) and the book value was $21.69 per share, representing a market-to-book ratio of 209%, compared to $41.11, $21.43, and 192%, respectively, at the end of 2013. Southern Company's common stock dividend for the second quarter 2014 was $0.5250 per share compared to $0.5075 per share in the second quarter 2013.

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Capital Requirements and Contractual Obligations

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Southern 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 $585 million will be required through June 30, 2015 to fund maturities of long-term debt.

The Southern Company system's construction program is currently estimated to be $6.9 billion for 2014, $5.6 billion for 2015, and $4.5 billion for 2016, which includes expenditures related to construction and start-up of the Kemper IGCC of $1.3 billion for 2014 and $208 million for 2015. The amounts related to the construction and start-up of the Kemper IGCC exclude SMEPA's proposed acquisition of a 15% ownership share of the Kemper IGCC for approximately $572 million (including construction costs for all prior periods relating to its proposed ownership interest). The Southern Company system's amounts include capital expenditures related to contractual purchase commitments for nuclear fuel and capital expenditures covered under long-term service agreements.

Southern Company anticipates that the Southern Company system's capital expenditure requirements will continue to decline through the middle of the decade, before rising again to meet additional requirements for environmental compliance and new generation.

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. 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 internal cash flow, short-term debt, 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 2014, as well as in subsequent years, will be contingent on Southern Company's investment opportunities and the Southern Company system's capital requirements.

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, 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.

On February 20, 2014, Georgia Power and the DOE entered into a loan guarantee agreement (Loan Guarantee Agreement), pursuant to which the DOE agreed to guarantee borrowings to be made by Georgia Power under a multi-advance credit facility (FFB Credit Facility) among Georgia Power, the DOE, and the FFB. Georgia Power is

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

obligated to reimburse the DOE for any payments the DOE is required to make to the FFB under the guarantee. Georgia Power's reimbursement obligations to the DOE are secured by a first priority lien on (i) Georgia Power's 45.7% ownership interest in Plant Vogtle Units 3 and 4 (primarily the units under construction, the related real property, and any nuclear fuel loaded in the reactor core) and (ii) Georgia Power's rights and obligations under the principal contracts relating to Plant Vogtle Units 3 and 4. Under the FFB Credit Facility, Georgia Power may make term loan borrowings through the FFB. Proceeds of borrowings made under the FFB Credit Facility will be used to reimburse Georgia Power for a portion of certain costs of construction relating to Plant Vogtle Units 3 and 4 that are eligible for financing under the Loan Guarantee Agreement (Eligible Project Costs). Aggregate borrowings under the FFB Credit Facility may not exceed the lesser of (i) 70% of Eligible Project Costs or (ii) approximately $3.46 billion. See Note 6 to the financial statements of Southern Company 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 June 30, 2014 would allow for borrowings of up to $1.9 billion under the FFB Credit Facility. Through June 30, 2014, Georgia Power has borrowed $1.0 billion under the FFB Credit Facility, leaving $0.9 billion of currently available borrowing ability.

Mississippi Power has received $245 million of DOE Grants 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 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 information regarding legislation related to the securitization of certain costs of the Kemper IGCC.

Southern Company'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 of the Southern Company system. To meet short-term cash needs and contingencies, Southern Company has substantial cash flow from operating activities and access to capital markets, including commercial paper programs which are backed by bank credit facilities.

At June 30, 2014, Southern Company and its subsidiaries had approximately $583 million of cash and cash equivalents. Committed credit arrangements with banks at June 30, 2014 were as follows:

	Expires														Executable Term Loans				Due Within One Year
Company	2014		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	163		110		—		—		1,030		1,303		1,303		53		—		53		185
Georgia Power	—		—		150		—		1,600		1,750		1,736		—		—		—		—
Gulf Power	20		60		165		30		—		275		275		50		—		50		30
Mississippi Power	40		95		165		—		—		300		300		25		40		65		70
Southern Power	—		—		—		—		500		500		499		—		—		—		—
Other	—		70		—		—		—		70		70		20		—		20		25
Total	$	223	$	335	$	480	$	30	$	4,130	$	5,198	$	5,183	$	148	$	40	$	188	$	310

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

30

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

rate pollution control revenue bonds outstanding requiring liquidity support as of June 30, 2014 was approximately $1.7 billion. Subsequent to June 30, 2014, an additional $40 million of variable rate pollution control revenue bonds, previously purchased and held by Georgia Power, were remarketed to the public and currently require liquidity support. In addition, at June 30, 2014, the traditional operating companies had $495 million of fixed rate pollution control revenue bonds that were required to be remarketed within the next 12 months. Subsequent to June 30, 2014, $45 million of these fixed rate pollution control revenue bonds were remarketed to the public and currently are not required to be remarketed within the next 12 months.

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

Details of short-term borrowings were as follows:

	Short-term Debt at June 30, 2014			Short-term Debt During the Period(a)
	Amount Outstanding		Weighted Average Interest Rate	Average Outstanding		Weighted Average Interest Rate	Maximum Amount Outstanding
	(in millions)			(in millions)			(in millions)
Commercial paper	$	1,567	0.2%	$	1,004	0.2%	$	1,582
Short-term bank debt	250		0.8%	19		0.8%	250
Total	$	1,817	0.3%	$	1,023	0.2%

(a)    Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 2014.

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

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, and construction of new generation at Georgia Power's Plant Vogtle Units 3 and 4.

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The maximum potential collateral requirements under these contracts at June 30, 2014 were as follows:

Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB and Baa2	$	9
At BBB- and/or Baa3	448
Below BBB- and/or Baa3	2,246

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 six months of 2014, Southern Company issued approximately 3.9 million shares of common stock for approximately $132.5 million through the employee and director stock plans, of which 150,000 shares related to Southern Company's performance share plan.

Since August 2013, Southern Company has used shares held in treasury, to the extent available, and newly-issued shares to satisfy the requirements under the Southern Investment Plan and the employee savings plan and, during the first six months of 2014, issued approximately 4.7 million shares for approximately $204.2 million.

The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first six months of 2014:

Company(a)	Senior Note Maturities		Revenue Bond Issuances and Remarketings of Purchased Bonds(b)		Revenue Bond Redemptions		Other Long-Term Debt Issuances			Other Long-Term Debt Redemptions(c)
	(in millions)
Southern Company	$	350	$	—	$	—	$	—		$	—
Georgia Power	—		—		37		1,000			3
Gulf Power	—		42		29		—			—
Mississippi Power	—		—		—		482			1
Southern Power	—		—		—		10			1
Other	—		—		—		—			10
Elimination(d)	—		—		—		(220		)	—
Total	$	350	$	42	$	66	$	1,272		$	15

(a) Alabama Power did not issue or redeem any long-term debt during the first six months of 2014.

(b) Includes remarketing by Gulf Power of $13 million aggregate principal amount of revenue bonds previously purchased and held by Gulf Power since December 2013.

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

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

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

32

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

In addition to the amounts reflected in the table above, in June 2014, Southern Company entered into a 90-day 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, including the investment by Southern Company in its subsidiaries.

In addition to the amounts reflected in the table above, in January 2014, Mississippi Power received an additional $75 million interest-bearing refundable deposit from SMEPA to be applied to the sale price for the pending sale of an undivided interest in the Kemper IGCC. See Note 3 to the financial statements of Southern Company in Item 8 of the Form 10-K under "Integrated Coal Gasification Combined Cycle – Proposed Sale of Undivided Interest to SMEPA" for additional information.

Georgia Power's "Other Long-Term Debt Issuances" reflected in the table above include initial borrowings under the FFB Credit Facility in an aggregate principal amount of $1.0 billion in February 2014. The interest rate applicable to $500 million of the initial advance under the FFB Credit Facility is 3.860% for an interest period that extends to February 20, 2044 (the final maturity date) and the interest rate applicable to the remaining $500 million is 3.488% for an interest period that extends to February 20, 2029 and is expected to be reset from time to time thereafter through the final maturity date. The final maturity date for all advances under the FFB Credit Facility is February 20, 2044. The proceeds of the initial borrowings under the FFB Credit Facility were used to reimburse Georgia Power for Eligible Project Costs relating to the construction of Plant Vogtle Units 3 and 4.

Under the Loan Guarantee Agreement, Georgia Power is subject to customary events of default, as well as cross-defaults to other indebtedness and events of default relating to any failure to make payments under the engineering, procurement, and construction contract, as amended, relating to Plant Vogtle Units 3 and 4 or certain other agreements providing intellectual property rights for Plant Vogtle Units 3 and 4. The Loan Guarantee Agreement also includes events of default specific to the DOE loan guarantee program, including the failure of Georgia Power or Southern Nuclear to comply with requirements of law or DOE loan guarantee program requirements. See Note 6 to the financial statements of Southern Company in Item 8 of the Form 10-K under "DOE Loan Guarantee Borrowings" for additional information.

In February 2014, Georgia Power repaid three four-month floating rate bank loans in an aggregate principal amount of $400 million.

Subsequent to June 30, 2014, Georgia Power reoffered to the public $40 million aggregate principal amount of Development Authority of Monroe County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Scherer Project), First Series 2009, which had been previously purchased and held by Georgia Power since 2010.

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.

33

PART I

Item 3. Quantitative And Qualitative Disclosures About Market Risk.

During the six months ended June 30, 2014, 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 second quarter 2014 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.

34

ALABAMA POWER COMPANY

35

ALABAMA POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2014			2013			2014			2013
	(in millions)						(in millions)
Operating Revenues:
Retail revenues	$	1,249		$	1,221		$	2,546		$	2,362
Wholesale revenues, non-affiliates	65			61			150			120
Wholesale revenues, affiliates	68			60			137			116
Other revenues	55			50			112			102
Total operating revenues	1,437			1,392			2,945			2,700
Operating Expenses:
Fuel	414			401			846			773
Purchased power, non-affiliates	39			28			96			48
Purchased power, affiliates	37			41			86			72
Other operations and maintenance	330			319			655			649
Depreciation and amortization	172			159			347			317
Taxes other than income taxes	88			87			177			177
Total operating expenses	1,080			1,035			2,207			2,036
Operating Income	357			357			738			664
Other Income and (Expense):
Allowance for equity funds used during construction	11			8			21			16
Interest expense, net of amounts capitalized	(63		)	(65		)	(125		)	(131		)
Other income (expense), net	(3		)	2			(8		)	1
Total other income and (expense)	(55		)	(55		)	(112		)	(114		)
Earnings Before Income Taxes	302			302			626			550
Income taxes	119			119			246			216
Net Income	183			183			380			334
Dividends on Preferred and Preference Stock	10			10			20			20
Net Income After Dividends on Preferred and Preference Stock	$	173		$	173		$	360		$	314

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2014		2013		2014		2013
	(in millions)				(in millions)
Net Income	$	183	$	183	$	380	$	334
Other comprehensive income (loss):
Qualifying hedges:
Reclassification adjustment for amounts included in net income, net of tax of $-, $-, $- and $-, respectively	—		1		1		1
Total other comprehensive income (loss)	—		1		1		1
Comprehensive Income	$	183	$	184	$	381	$	335

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

36

ALABAMA POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Six Months Ended June 30,
	2014			2013
	(in millions)
Operating Activities:
Net income	$	380		$	334
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	416			403
Deferred income taxes	49			53
Allowance for equity funds used during construction	(21		)	(16		)
Regulatory deferrals	(44		)	(9		)
Other, net	4			(3		)
Changes in certain current assets and liabilities —
-Receivables	(120		)	(65		)
-Fossil fuel stock	94			76
-Materials and supplies	(2		)	22
-Other current assets	(57		)	(45		)
-Accounts payable	(94		)	(93		)
-Accrued taxes	104			60
-Accrued compensation	(17		)	(54		)
-Retail fuel cost over recovery	(23		)	12
-Other current liabilities	5			4
Net cash provided from operating activities	674			679
Investing Activities:
Property additions	(637		)	(518		)
Nuclear decommissioning trust fund purchases	(121		)	(120		)
Nuclear decommissioning trust fund sales	121			120
Cost of removal, net of salvage	(30		)	(19		)
Change in construction payables	71			(21		)
Other investing activities	(13		)	30
Net cash used for investing activities	(609		)	(528		)
Financing Activities:
Increase in notes payable, net	27			46
Capital contributions from parent company	12			10
Payment of preferred and preference stock dividends	(20		)	(20		)
Payment of common stock dividends	(275		)	(265		)
Other financing activities	1			—
Net cash used for financing activities	(255		)	(229		)
Net Change in Cash and Cash Equivalents	(190		)	(78		)
Cash and Cash Equivalents at Beginning of Period	295			137
Cash and Cash Equivalents at End of Period	$	105		$	59
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $8 and $6 capitalized for 2014 and 2013, respectively)	$	114		$	119
Income taxes, net	141			146
Noncash transactions—accrued property additions at end of period	89			10

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)

Assets	At June 30, 2014			At December 31, 2013
	(in millions)
Current Assets:
Cash and cash equivalents	$	105		$	295
Receivables —
Customer accounts receivable	391			341
Unbilled revenues	156			142
Other accounts and notes receivable	39			30
Affiliated companies	62			54
Accumulated provision for uncollectible accounts	(9		)	(8		)
Fossil fuel stock, at average cost	235			329
Materials and supplies, at average cost	377			375
Vacation pay	63			63
Prepaid expenses	119			57
Other regulatory assets, current	4			7
Other current assets	16			6
Total current assets	1,558			1,691
Property, Plant, and Equipment:
In service	22,533			22,092
Less accumulated provision for depreciation	8,315			8,114
Plant in service, net of depreciation	14,218			13,978
Nuclear fuel, at amortized cost	348			332
Construction work in progress	808			748
Total property, plant, and equipment	15,374			15,058
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	57			54
Nuclear decommissioning trusts, at fair value	749			714
Miscellaneous property and investments	82			80
Total other property and investments	888			848
Deferred Charges and Other Assets:
Deferred charges related to income taxes	525			519
Prepaid pension costs	284			276
Deferred under recovered regulatory clause revenues	65			25
Other regulatory assets, deferred	702			692
Other deferred charges and assets	134			142
Total deferred charges and other assets	1,710			1,654
Total Assets	$	19,530		$	19,251

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

38

ALABAMA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholder's Equity	At June 30, 2014			At December 31, 2013
	(in millions)
Current Liabilities:
Securities due within one year	$	54		$	—
Notes payable	27			—
Accounts payable —
Affiliated	193			198
Other	327			339
Customer deposits	86			85
Accrued taxes —
Accrued income taxes	67			11
Other accrued taxes	85			33
Accrued interest	64			61
Accrued vacation pay	53			53
Accrued compensation	62			74
Other regulatory liabilities, current	33			37
Other current liabilities	40			41
Total current liabilities	1,091			932
Long-term Debt	6,180			6,233
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	3,646			3,603
Deferred credits related to income taxes	73			75
Accumulated deferred investment tax credits	129			133
Employee benefit obligations	186			195
Asset retirement obligations	751			730
Other cost of removal obligations	856			828
Other regulatory liabilities, deferred	260			259
Deferred over recovered regulatory clause revenues	—			15
Other deferred credits and liabilities	65			61
Total deferred credits and other liabilities	5,966			5,899
Total Liabilities	13,237			13,064
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	2,281			2,262
Retained earnings	2,130			2,044
Accumulated other comprehensive loss	(25		)	(26		)
Total common stockholder's equity	5,608			5,502
Total Liabilities and Stockholder's Equity	$	19,530		$	19,251

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

39

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

SECOND QUARTER 2014 vs. SECOND QUARTER 2013

AND

YEAR-TO-DATE 2014 vs. YEAR-TO-DATE 2013

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 given economic conditions, 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

Second Quarter 2014 vs. Second Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$—	—	$46	14.6

Alabama Power's net income after dividends on preferred and preference stock for the second quarter 2014 and the corresponding period in 2013 was $173 million.

Alabama Power's net income after dividends on preferred and preference stock for year-to-date 2014 was $360million compared to $314 million for the corresponding period in 2013. The increase in net income was related to an increase in revenue primarily due to colder weather in the first quarter 2014 as compared to the corresponding period in 2013, partially offset by increases in operating expenses.

Retail Revenues

Second Quarter 2014 vs. Second Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$28	2.3	$184	7.8

In the second quarter 2014, retail revenues were $1.25 billion compared to $1.22 billion for the corresponding period in 2013. For year-to-date 2014, retail revenues were $2.55 billion compared to $2.36 billion for the corresponding period in 2013.

40

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:

	Second Quarter 2014					Year-to-Date 2014
	(in millions)			(% change)		(in millions)			(% change)
Retail – prior year	$	1,221				$	2,362
Estimated change resulting from –
Rates and pricing	17			1.4		37			1.5
Sales decline	(4		)	(0.3	)	(3		)	(0.1	)
Weather	6			0.5		58			2.5
Fuel and other cost recovery	9			0.7		92			3.9
Retail – current year	$	1,249		2.3	%	$	2,546		7.8	%

Revenues associated with changes in rates and pricing increased in the second quarter and year-to-date 2014 when compared to the corresponding periods in 2013 due to increased revenues associated with Rate CNP Environmental primarily resulting from the inclusion of pre-2005 environmental assets. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Rate CNP" of Alabama Power in Item 7 of the Form 10-K for additional information regarding the revision to Rate CNP Environmental.

Revenues attributable to changes in sales decreased slightly in the second quarter and year-to-date 2014 when compared to the corresponding periods in 2013. Weather-adjusted residential KWH energy sales decreased 1.5% in the second quarter and 0.8% for year-to-date 2014 as a result of decreased customer usage. Weather-adjusted commercial KWH energy sales decreased 1.0% in the second quarter and 0.7% for year-to-date 2014 as a result of decreased customer usage. Industrial KWH energy sales increased 2.7% in the second quarter and 3.1% for year-to-date 2014 as a result of an increase in demand resulting from changes in production levels primarily in the primary metals, chemicals, forest products, and automotive and plastics sectors.

Revenues resulting from changes in weather increased in the second quarter 2014 due to warmer weather experienced in Alabama Power's service territory compared to the corresponding period in 2013. For the second quarter 2014, the resulting increases were 0.5% and 1.1% for residential and commercial sales revenue, respectively.

Revenues resulting from changes in weather increased year-to-date 2014 primarily due to colder weather experienced in Alabama Power's service territory in first quarter 2014 and warmer weather in the second quarter 2014 when compared to the corresponding periods in 2013. For year-to-date 2014, the resulting increases were 4.3% and 2.3% for residential and commercial sales revenue, respectively.

Fuel and other cost recovery revenues increased in the second quarter and year-to-date 2014 when compared to the corresponding periods in 2013 primarily due to an increase in fuel costs associated with an increase 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

Second Quarter 2014 vs. Second Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$4	6.6	$30	25.0

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

41

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 second quarter 2014, wholesale revenues from sales to non-affiliates were $65 million compared to $61 million for the corresponding period in 2013. The increase was not material.

For year-to-date 2014, wholesale revenues from sales to non-affiliates were $150 million compared to $120 million for the corresponding period in 2013. The increase was primarily due to a 19.4% increase in KWH sales primarily due the colder weather experienced during the first quarter 2014 and an increase of 4.4% in the price of energy primarily due to higher natural gas prices.

Wholesale Revenues – Affiliates

Second Quarter 2014 vs. Second Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$8	13.3	$21	18.1

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

In the second quarter 2014, wholesale revenues from sales to affiliates were $68 million compared to $60 million for the corresponding period in 2013. The increase was primarily due to a 7.6% increase in the price of energy primarily due to higher natural gas prices and a 7.6% increase in KWH sales primarily due to the availability of Alabama Power's lower cost generation.

For year-to-date 2014, wholesale revenues from sales to affiliates were $137 million compared to $116 million for the corresponding period in 2013. The increase was primarily due to a 17.2% increase in the price of energy due to higher natural gas prices and a 1.4% increase in KWH sales primarily due to the availability of Alabama Power's lower cost generation.

Other Revenues

Second Quarter 2014 vs. Second Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$5	10.0	$10	9.8

In the second quarter 2014, other revenues were $55 million compared to $50 million for the corresponding period in 2013. For year-to-date 2014, other revenues were $112 million compared to $102 million for the corresponding period in 2013. The increases were primarily due to increases in co-generation steam revenues, transmission revenues related to open access transmission tariff, and transmission service agreement revenues.

42

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Fuel and Purchased Power Expenses

	Second Quarter 2014 vs. Second Quarter 2013				Year-to-Date 2014 vs. Year-to-Date 2013
	(change in millions)			(% change)	(change in millions)		(% change)
Fuel	$	13		3.2	$	73	9.4
Purchased power – non-affiliates	11			39.3	48		100.0
Purchased power – affiliates	(4		)	(9.8)	14		19.4
Total fuel and purchased power expenses	$	20			$	135

In the second quarter 2014, total fuel and purchased power expenses were $490 million compared to $470 million for the corresponding period in 2013. The increase was primarily due to an $11 million increase related to the volume of KWHs generated, an $11 million increase in the average cost of purchased power, and a $3 million increase in the average cost of fuel, partially offset by a $5 million decrease in the volume of KWHs purchased.

For year-to-date 2014, total fuel and purchased power expenses were $1.03 billion compared to $893 million for the corresponding period in 2013. The increase was primarily due to a $42 million increase related to the volume of KWHs generated, a $35 million increase in the average cost of purchased power, a $32 million increase in the average cost of fuel, and a $26 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 clauses. Alabama Power, along with the Alabama PSC, continuously monitors the under/over recovered balance to determine whether adjustments to billings rates are required. See FUTURE EARNINGS POTENTIAL – "PSC Matters – Retail Energy Cost Recovery" of Alabama Power in Item 7 of the Form 10-K for additional information.

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

	Second Quarter 2014	Second Quarter 2013	Year-to-Date 2014	Year-to-Date 2013
Total generation (billions of KWHs)	16	16	33	32
Total purchased power (billions of KWHs)	1	1	3	2
Sources of generation (percent) —
Coal	53	54	53	51
Nuclear	24	20	23	22
Gas	16	16	16	16
Hydro	7	10	8	11
Cost of fuel, generated (cents per net KWH) —
Coal	3.30	3.34	3.35	3.35
Nuclear	0.85	0.83	0.86	0.82
Gas	3.80	3.59	3.99	3.44
Average cost of fuel, generated (cents per net KWH)(a)	2.76	2.83	2.83	2.74
Average cost of purchased power (cents per net KWH)(b)	5.88	5.01	6.18	4.99

(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.

43

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Fuel

In the second quarter 2014, fuel expense was $414 million compared to $401 million for the corresponding period in 2013. The increase was primarily due to a 26.1% decrease in the volume of KWHs generated by hydro facilities as a result of less rainfall, a 21.8% increase in KWHs generated by nuclear fuel due to an outage in the second quarter 2013, and a 5.8% increase in the average cost of natural gas per KWH generated, which excludes fuel associated with tolling agreements.

For year-to-date 2014, fuel expense was $846 million compared to $773 million for the corresponding period in 2013. The increase was primarily due to a 22.2% decrease in the volume of KWHs generated by hydro facilities as a result of less rainfall, a 15.9% increase in the average cost of natural gas per KWH generated, which excludes fuel associated with tolling agreements, a 9.3% increase in KWHs generated by nuclear fuel due to an outage in the second quarter 2013, and a 7.5% increase in the volume of KWHs generated by coal.

Purchased Power – Non-Affiliates

In the second quarter 2014, purchased power expense from non-affiliates was $39 million compared to $28 million for the corresponding period in 2013. The increase was related to a 41.8% increase in the average cost per KWH purchased primarily due to the addition of a new PPA in 2014 partially offset by a 3.9% decrease in the amount of energy purchased due to availability of Alabama Power's lower cost generation.

For year-to-date 2014, purchased power expense from non-affiliates was $96 million compared to $48 million for the corresponding period in 2013. The increase was related to an 81.1% increase in the average cost per KWH purchased primarily due to demand during peak periods and the addition of a new PPA in 2014 and a 9.1% increase in the volume of KWHs purchased to meet the demand created by colder weather in the first quarter 2014 compared to the corresponding period in 2013.

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

Purchased Power – Affiliates

In the second quarter 2014, purchased power expense from affiliates was $37 million compared to $41 million for the corresponding period in 2013. The decrease was related to a 10.0% decrease in the amount of energy purchased primarily due to utilization of Alabama Power's resources and a 1.0% decrease in the average cost per KWH purchased due to availability of Alabama Power's lower cost generation.

For year-to-date 2014, purchased power expense from affiliates was $86 million compared to $72 million for the corresponding period in 2013. The increase was related to a 35.6% increase in the volume of KWHs purchased to meet the demand created by colder weather in the first quarter 2014 compared to the corresponding period in 2013 partially offset by an 11.9% decrease in the average cost per KWH purchased due to the availability of Southern Company system resources at the time of purchase.

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

Other Operations and Maintenance Expenses

Second Quarter 2014 vs. Second Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$11	3.4	$6	0.9

In the second quarter 2014, other operations and maintenance expenses were $330 million compared to $319 million for the corresponding period in 2013. For year-to-date 2014, other operations and maintenance expenses

44

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

were $655 million compared to $649 million for the corresponding period in 2013. The increases were primarily due to increases in labor and contract labor costs. The increases were partially offset by the implementation of an accounting order in 2014 allowing deferral of non-nuclear outage costs. Alabama Power deferred approximately $16 million and $41 million of non-nuclear outage expenditures in the second quarter and for the first six months of 2014, respectively. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Non-Nuclear Outage Accounting Order" of Alabama Power in Item 7 of the Form 10-K for additional information.

Depreciation and Amortization

Second Quarter 2014 vs. Second Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$13	8.2	$30	9.5

In the second quarter 2014, depreciation and amortization was $172 million compared to $159 million for the corresponding period in 2013. For year-to-date 2014, depreciation and amortization was $347 million compared to $317 million for the corresponding period in 2013. These increases were primarily due to an increase in depreciation rates related to environmental assets and the deferral in 2013 of certain costs under an accounting order. Depreciation related to environmental assets is offset by revenues associated with Rate CNP Environmental. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Rate CNP" of Alabama Power in Item 7 of the Form 10-K for additional information regarding Alabama Power's revision to Rate CNP Environmental. See also MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Compliance and Pension Cost Accounting Order" of Alabama Power in Item 7 of the Form 10-K for additional information regarding Alabama Power's deferral of costs under this accounting order.

Other Income (Expense), Net

Second Quarter 2014 vs. Second Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$(5)	N/M	$(9)	N/M

N/M – Not meaningful

In the second quarter 2014, other income (expense), net was $(3) million compared to $2 million for the corresponding period in 2013. For year-to-date 2014, other income (expense), net was $(8) million compared to $1 million for the corresponding period in 2013. The changes were primarily due to increases in non-operating expenses and decreases in non-operating income related to a decrease in sales of non-utility property in 2014.

Income Taxes

Second Quarter 2014 vs. Second Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$—	—	$30	13.9

In the second quarter 2014 and the corresponding period in 2013, income taxes were $119 million.

For year-to-date 2014, income taxes were $246 million compared to $216 million for the corresponding period in 2013. The increase was primarily due to higher 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,

45

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 is subject to a number of factors. These factors include weather, competition, new energy contracts with other utilities, energy conservation practiced 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 – "PSC Matters – Environmental Accounting Order" of Alabama Power in Item 7 of the Form 10-K and "PSC Matters – Environmental Accounting Order" herein for additional information regarding Alabama Power's plan for compliance with environmental statutes and regulations.

Air Quality

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Air Quality" of Alabama Power in Item 7 of the Form 10-K for additional information regarding the Cross State Air Pollution Rule (CSAPR) and the EPA's proposed rules regarding the regulation of excess emissions during periods of startup, shutdown, or malfunction (SSM).

On April 29, 2014, the U.S. Supreme Court overturned the U.S. Court of Appeals for the District of Columbia Circuit's August 2012 decision to vacate CSAPR and remanded the case back to the U.S. Court of Appeals for the District of Columbia Circuit for further proceedings. On June 26, 2014, the EPA requested that the U.S. Court of Appeals for the District of Columbia Circuit lift the stay on CSAPR and approve a revised schedule with compliance to begin on January 1, 2015.

On June 10, 2014, the EPA entered into a revised settlement agreement requiring it to issue a supplemental proposed SSM rule by September 5, 2014 and finalize the proposed rule by May 22, 2015.

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

Water Quality

On April 21, 2014, the EPA and the U.S. Army Corps of Engineers jointly published a proposed rule to revise the regulatory definition of waters of the U.S. for all Clean Water Act (CWA) programs, significantly expanding the scope of federal jurisdiction under the CWA. If finalized as proposed, this rule could significantly increase permitting and regulatory requirements and costs associated with the siting of new facilities and the installation, expansion, and maintenance of transmission and distribution lines. In addition, the rule as proposed could have

46

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

significant impacts on economic development projects which could affect customer demand growth. The ultimate impact of the proposed rule will depend on the specific requirements of the final rule and the outcome of any legal challenges and cannot be determined at this time.

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Water Quality" of Alabama Power in Item 7 of the Form 10-K for additional information regarding the EPA's rulemaking for cooling water intake structures.

On May 19, 2014, the EPA signed a final rule establishing standards for reducing effects on fish and other aquatic life caused by new and existing cooling water intake structures at existing power plants and manufacturing facilities. The ultimate outcome of this final rule will depend on the results of additional studies and implementation of the rule by state regulators, but could result in additional capital and operational costs associated with changes to existing intake structures and cooling systems and increased costs associated with the construction of new generating units. The ultimate impact of this rule will depend on the outcome of any legal challenges and cannot be determined at this time.

Global Climate Issues

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues" of Alabama Power in Item 7 of the Form 10-K for additional information regarding the EPA's current and proposed regulation of GHG emissions under the Clean Air Act.

On June 18, 2014, the EPA published the proposed Clean Power Plan, setting forth guidelines for states to develop plans to address CO₂ emissions from existing fossil fuel-fired electric generating units. The EPA's proposed guidelines establish state-specific interim and final CO₂ emission rate goals to be achieved between 2020 and 2029 and in 2030 and thereafter. The EPA also published the proposed CO₂ performance standards for modified and reconstructed fossil fuel-fired electric generating units. If finalized as proposed, the proposed guidelines and standards could result in operational restrictions and material compliance costs, including capital expenditures, that could impact unit retirement and replacement decisions. Also, additional compliance costs could affect results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates. Further, any resulting higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively impact results of operations, cash flows, and financial condition. The ultimate impact of these proposals will depend on the specific requirements of the final guidelines and performance standards, implementation by states, and the outcome of any legal challenges and cannot be determined at this time.

On June 23, 2014, the U.S. Supreme Court struck down a portion of the EPA's program for GHG permitting under the Prevention of Significant Deterioration and Title V operating permit programs, holding that a facility's GHG emissions alone could not trigger a requirement to obtain a permit and that the EPA did not have the authority to tailor the statutory permitting thresholds. The ultimate impact of this decision cannot be determined at this time.

PSC Matters

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters" of Alabama Power in Item 7 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 for Alabama Power is reported in Note (B) to the Condensed Financial Statements herein.

Environmental Accounting Order

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

As part of its environmental compliance strategy, Alabama Power plans to retire Plant Gorgas Units 6 and 7. These units represent 200 MWs of Alabama Power's approximately 12,200 MWs of generating capacity. Alabama Power

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ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

also plans to cease 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. Additionally, Alabama Power expects to cease using coal at Plant Barry Unit 3 (225 MWs) and Plant Greene County Units 1 and 2 (300 MWs) and begin operating those units solely on natural gas. These plans are expected to be effective no later than April 2016.

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.

Nuclear Waste Fund Accounting Order

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Other Matters" of Alabama Power in Item 7 of the Form 10-K and "Other Matters" herein for additional information regarding the court order for the DOE to set the spent fuel depositary fees at zero.

On August 5, 2014, the Alabama PSC issued an order to provide for the continued recovery from customers of amounts associated with the permanent disposal of nuclear waste from the operation of Plant Farley. In accordance with the order, effective May 16, 2014, Alabama Power is authorized to recover from customers an amount equal to the prior fee and to record the amounts in a regulatory liability account (approximately $14 million annually). Upon the DOE meeting the requirements of the Nuclear Waste Policy Act of 1982 and a new spent fuel depositary fee being put in place, the accumulated balance in the regulatory liability account will be available for purposes of the associated cost responsibility. In the event the balance is later determined to be more than needed, those amounts would be used for the benefit of customers subject to the approval of the Alabama PSC. The ultimate outcome of this matter cannot be determined at this time.

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 increased generally throughout the U.S. In particular, personal injury, property damage, and other claims for damages alleged to have been caused by CO₂ and other emissions, coal combustion residuals, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters, have become more frequent.

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 the Notes 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.

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Other Matters" of Southern Company in Item 7 of the Form 10-K for additional information regarding the NRC's performance of additional operational and safety reviews of nuclear facilities in the U.S. following the major earthquake and tsunami that struck Japan in 2011.

Additionally, there are certain risks associated with the 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 events cannot be determined at this time.

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ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Other Matters" of Alabama Power in Item 7 of the Form 10-K for additional information regarding the court order for the DOE to set the spent fuel depositary fees at zero. On March 18, 2014, the U.S. Court of Appeals for the District of Columbia Circuit denied the DOE's request for rehearing of the November 2013 panel decision ordering that the DOE propose the nuclear waste fund fee be changed to zero. The DOE formally set the fee to zero effective May 16, 2014. See "PSC Matters – Nuclear Waste Fund Accounting Order" herein for information regarding an accounting order issued by the Alabama PSC which provides for continued recovery from customers of amounts associated with the permanent disposal of nuclear waste from the operation of Plant Farley.The ultimate outcome of this matter cannot be determined at this time.

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

On May 28, 2014, the Financial Accounting Standards Board issued ASC 606, Revenue from Contracts with Customers. ASC 606 revises the accounting for revenue recognition and is effective for fiscal years beginning after December 15, 2016. Alabama Power is currently evaluating the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined.

FINANCIAL CONDITION AND LIQUIDITY

Overview

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Alabama Power in Item 7 of the Form 10-K for additional information. Alabama Power's financial condition remained stable at June 30, 2014. Alabama Power intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.

Net cash provided from operating activities totaled $674 million for the first six months of 2014, a decrease of $5 million as compared to the first six months of 2013. The decrease in net cash provided from operating activities was primarily due to the timing of the collection of accounts receivable, partially offset by an increase in net income as compared to the first six months of 2013. Net cash used for investing activities totaled $609 million for the first six months of 2014 primarily due to gross property additions related to distribution, environmental, transmission, and steam generation. Net cash used for financing activities totaled $255 million for the first six months of 2014 primarily due to the 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 six months of 2014 include an increase of $316 million in property, plant, and equipment, primarily due to additions to distribution, environmental, transmission, and steam generation and a decrease of $190 million in cash and cash equivalents.

49

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Capital Requirements and Contractual Obligations

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of 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 $54 million will be required through June 30, 2015 to fund maturities of long-term debt.

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

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

Sources of Capital

Alabama Power plans to obtain the funds 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.

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 June 30, 2014, Alabama Power had approximately $105 million of cash and cash equivalents. Committed credit arrangements with banks at June 30, 2014 were as follows:

Expires(a)										Executable Term Loans				Due Within One Year
2014		2015		2018		Total		Unused		One Year		Two Years		Term Out		No Term Out
(in millions)						(in millions)				(in millions)				(in millions)
$	163	$	110	$	1,030	$	1,303	$	1,303	$	53	$	—	$	53	$	185

(a) No credit arrangements expire in 2016 or 2017.

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 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

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ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

over a specified threshold. Alabama Power is currently in compliance with all such covenants. None of the arrangements contain material adverse change clauses at the time of borrowings. Alabama Power expects to renew its credit arrangements, as needed, prior to expiration.

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. 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 June 30, 2014, Alabama Power had $784 million of outstanding variable rate pollution control revenue bonds requiring liquidity support. In addition, at June 30, 2014, Alabama Power had $280 million of fixed rate pollution control revenue bonds that will be required to be remarketed within the next 12 months.

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 June 30, 2014			Short-term Debt During the Period(a)
	Amount Outstanding		Weighted Average Interest Rate	Average Outstanding		Weighted Average Interest Rate	Maximum Amount Outstanding
	(in millions)			(in millions)			(in millions)
Commercial Paper	$	27	0.1%	$	7	0.1%	$	52

(a) Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 2014.

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

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 June 30, 2014, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $311 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 Alabama Power's ability to access capital markets, particularly the short-term debt market and the variable rate pollution control revenue bond market.

Financing Activities

Alabama Power did not issue or redeem any securities during the six months ended June 30, 2014.

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.

51

GEORGIA POWER COMPANY

52

GEORGIA POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2014			2013			2014			2013
	(in millions)						(in millions)
Operating Revenues:
Retail revenues	$	2,000		$	1,879		$	4,050		$	3,608
Wholesale revenues, non-affiliates	80			73			189			135
Wholesale revenues, affiliates	10			5			31			11
Other revenues	96			85			185			170
Total operating revenues	2,186			2,042			4,455			3,924
Operating Expenses:
Fuel	619			557			1,371			1,076
Purchased power, non-affiliates	63			61			142			111
Purchased power, affiliates	166			176			350			351
Other operations and maintenance	451			397			878			828
Depreciation and amortization	209			204			417			404
Taxes other than income taxes	106			95			209			190
Total operating expenses	1,614			1,490			3,367			2,960
Operating Income	572			552			1,088			964
Other Income and (Expense):
Allowance for equity funds used during construction	10			7			16			13
Interest expense, net of amounts capitalized	(90		)	(96		)	(174		)	(187		)
Other income (expense), net	1			1			(1		)	(1		)
Total other income and (expense)	(79		)	(88		)	(159		)	(175		)
Earnings Before Income Taxes	493			464			929			789
Income taxes	177			177			343			301
Net Income	316			287			586			488
Dividends on Preferred and Preference Stock	5			5			9			9
Net Income After Dividends on Preferred and Preference Stock	$	311		$	282		$	577		$	479

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2014		2013		2014		2013
	(in millions)				(in millions)
Net Income	$	316	$	287	$	586	$	488
Other comprehensive income (loss):
Qualifying hedges:
Reclassification adjustment for amounts included in net income, net of tax of $-, $1, $- and $1, respectively	1		—		1		1
Total other comprehensive income (loss)	1		—		1		1
Comprehensive Income	$	317	$	287	$	587	$	489

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

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GEORGIA POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Six Months Ended June 30,
	2014			2013
	(in millions)
Operating Activities:
Net income	$	586		$	488
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	503			487
Deferred income taxes	121			126
Allowance for equity funds used during construction	(16		)	(13		)
Retail fuel cost over recovery—long-term	(44		)	(123		)
Deferred expenses	31			31
Other, net	(12		)	(8		)
Changes in certain current assets and liabilities —
-Receivables	(353		)	(123		)
-Fossil fuel stock	255			56
-Prepaid income taxes	(7		)	5
-Other current assets	(14		)	34
-Accounts payable	(140		)	43
-Accrued taxes	(65		)	(14		)
-Accrued compensation	(15		)	(66		)
-Retail fuel cost over recovery—short-term	(14		)	1
-Other current liabilities	27			7
Net cash provided from operating activities	843			931
Investing Activities:
Property additions	(906		)	(765		)
Investment of restricted cash	—			(18		)
Distribution of restricted cash	—			18
Nuclear decommissioning trust fund purchases	(324		)	(427		)
Nuclear decommissioning trust fund sales	322			426
Cost of removal, net of salvage	(12		)	(27		)
Change in construction payables, net of joint owner portion	52			(2		)
Prepaid long-term service agreements	(47		)	(9		)
Other investing activities	(2		)	(3		)
Net cash used for investing activities	(917		)	(807		)
Financing Activities:
Increase (decrease) in notes payable, net	(359		)	314
Proceeds —
Capital contributions from parent company	24			21
Pollution control revenue bonds issuances	—			18
Senior notes issuances	—			650
FFB loan	1,000			—
Redemptions —
Pollution control revenue bonds	(37		)	(18		)
Senior notes	—			(650		)
Payment of preferred and preference stock dividends	(9		)	(9		)
Payment of common stock dividends	(477		)	(454		)
FFB loan issuance costs	(49		)	(1		)
Other financing activities	(3		)	(11		)
Net cash provided from (used for) financing activities	90			(140		)
Net Change in Cash and Cash Equivalents	16			(16		)
Cash and Cash Equivalents at Beginning of Period	30			45
Cash and Cash Equivalents at End of Period	$	46		$	29
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $8 and $6 capitalized for 2014 and 2013, respectively)	$	157		$	169
Income taxes, net	145			100
Noncash transactions—accrued property additions at end of period	267			238

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

54

GEORGIA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Assets	At June 30, 2014			At December 31, 2013
	(in millions)
Current Assets:
Cash and cash equivalents	$	46		$	30
Receivables —
Customer accounts receivable	609			512
Unbilled revenues	260			209
Joint owner accounts receivable	76			67
Other accounts and notes receivable	75			117
Affiliated companies	19			21
Accumulated provision for uncollectible accounts	(6		)	(5		)
Fossil fuel stock, at average cost	487			742
Materials and supplies, at average cost	417			409
Vacation pay	88			88
Prepaid income taxes	85			97
Other regulatory assets, current	61			66
Other current assets	82			54
Total current assets	2,299			2,407
Property, Plant, and Equipment:
In service	30,545			30,132
Less accumulated provision for depreciation	11,056			10,970
Plant in service, net of depreciation	19,489			19,162
Other utility plant, net	226			240
Nuclear fuel, at amortized cost	519			523
Construction work in progress	3,737			3,500
Total property, plant, and equipment	23,971			23,425
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	49			46
Nuclear decommissioning trusts, at fair value	782			751
Miscellaneous property and investments	43			44
Total other property and investments	874			841
Deferred Charges and Other Assets:
Deferred charges related to income taxes	705			718
Prepaid pension costs	128			118
Deferred under recovered regulatory clause revenues	244			—
Other regulatory assets, deferred	1,164			1,152
Other deferred charges and assets	284			246
Total deferred charges and other assets	2,525			2,234
Total Assets	$	29,669		$	28,907

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

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GEORGIA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholder's Equity	At June 30, 2014			At December 31, 2013
	(in millions)
Current Liabilities:
Securities due within one year	$	5		$	5
Notes payable	689			1,047
Accounts payable —
Affiliated	444			417
Other	437			472
Customer deposits	251			246
Accrued taxes —
Accrued income taxes	38			—
Other accrued taxes	215			321
Accrued interest	96			91
Accrued vacation pay	60			61
Accrued compensation	75			80
Liabilities from risk management activities	11			13
Nuclear decommissioning trust securities lending collateral	14			9
Other regulatory liabilities, current	21			17
Other current liabilities	148			127
Total current liabilities	2,504			2,906
Long-term Debt	9,594			8,633
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	5,297			5,200
Deferred credits related to income taxes	109			112
Accumulated deferred investment tax credits	198			203
Employee benefit obligations	539			542
Asset retirement obligations	1,205			1,210
Other cost of removal obligations	64			43
Other deferred credits and liabilities	171			201
Total deferred credits and other liabilities	7,583			7,511
Total Liabilities	19,681			19,050
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	5,665			5,633
Retained earnings	3,663			3,565
Accumulated other comprehensive loss	(4		)	(5		)
Total common stockholder's equity	9,722			9,591
Total Liabilities and Stockholder's Equity	$	29,669		$	28,907

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

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GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

SECOND QUARTER 2014 vs. SECOND QUARTER 2013

AND

YEAR-TO-DATE 2014 vs. YEAR-TO-DATE 2013

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 given economic conditions, 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 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

Second Quarter 2014 vs. Second Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$29	10.3	$98	20.5

Georgia Power's net income after dividends on preferred and preference stock for the second quarter 2014 was $311 million compared to $282 million for the corresponding period in 2013. The increase was primarily due to an increase in retail base revenues effective January 1, 2014 as authorized under the 2013 ARP and warmer weather in the second quarter 2014 as compared to the corresponding period in 2013, partially offset by higher non-fuel operations and maintenance expenses.

Georgia Power's net income after dividends on preferred and preference stock for year-to-date 2014 was $577 million compared to $479 million for the corresponding period in 2013. The increase was primarily due to colder weather in the first quarter 2014 and warmer weather in the second quarter 2014 as compared to the corresponding periods in 2013 and an increase in retail base revenues effective January 1, 2014 as authorized under the 2013 ARP, partially offset by higher non-fuel operations and maintenance expenses.

Retail Revenues

Second Quarter 2014 vs. Second Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$121	6.4	$442	12.3

In the second quarter 2014, retail revenues were $2.00 billion compared to $1.88 billion for the corresponding period in 2013. For year-to-date 2014, retail revenues were $4.05 billion compared to $3.61 billion for the corresponding period in 2013.

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Details of the changes in retail revenues were as follows:

	Second Quarter 2014				Year-to-Date  2014
	(in millions)		(% change)		(in millions)		(% change)
Retail – prior year	$	1,879			$	3,608
Estimated change resulting from –
Rates and pricing	40		2.1		80		2.2
Sales growth	11		0.6		22		0.6
Weather	28		1.5		80		2.2
Fuel cost recovery	42		2.2		260		7.3
Retail – current year	$	2,000	6.4	%	$	4,050	12.3	%

Revenues associated with changes in rates and pricing increased in the second quarter and year-to-date 2014 when compared to the corresponding periods in 2013 primarily due to base tariff increases effective January 1, 2014, as approved by the Georgia PSC in 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 as well as higher 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 second quarter and year-to-date 2014 when compared to the corresponding periods in 2013. Weather-adjusted residential KWH sales increased 0.5%, weather-adjusted commercial KWH sales increased 0.8%, and weather-adjusted industrial KWH sales increased 1.5% in the second quarter 2014 when compared to the corresponding period in 2013. For year-to-date 2014, weather-adjusted residential KWH sales increased 1.4%, weather-adjusted commercial KWH sales increased 0.2%, and weather-adjusted industrial KWH sales increased 1.3% when compared to the corresponding period in 2013. An increase of 17,147 residential customers since June 30, 2013 contributed to the increase in weather-adjusted residential KWH sales. Increased demand in the primary metals, non-manufacturing, textiles, and chemicals sectors was the main contributor to the increase in weather-adjusted industrial sales.

Fuel revenues and costs are allocated between retail and wholesale jurisdictions. Retail fuel cost recovery revenues increased $42 million and $260 million in the second quarter and year-to-date 2014, respectively, when compared to the corresponding periods in 2013 due to higher natural gas costs and higher energy sales. Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these fuel cost recovery provisions, fuel revenues generally equal fuel expenses and do not affect net income. See FUTURE EARNINGS POTENTIAL – "PSC Matters – Fuel Cost Recovery" herein for additional information.

Wholesale Revenues – Non-Affiliates

Second Quarter 2014 vs. Second Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$7	9.6	$54	40.0

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. Capacity revenues reflect the recovery of fixed costs and a return on investment. Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Georgia Power's and the Southern Company system's generation, demand for energy within the Southern Company system's service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. Short-term opportunity sales are made at market-based rates that generally provide a margin above Georgia Power's variable cost of energy.

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GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

In the second quarter 2014, wholesale revenues from sales to non-affiliates were $80 million compared to $73 million in the corresponding period in 2013 due to increased demand resulting from warmer weather in the second quarter 2014 as compared to the corresponding period in 2013 and the lower cost of Georgia Power-owned generation compared to the market cost of available energy.

For year-to-date 2014, wholesale revenues from sales to non-affiliates were $189 million compared to $135 million for the corresponding period in 2013 due to increased demand resulting from colder weather in the first quarter 2014 and warmer weather in the second quarter 2014 as compared to the corresponding periods in 2013 and the lower cost of Georgia Power-owned generation compared to the market cost of available energy.

Wholesale Revenues – Affiliates

Second Quarter 2014 vs. Second Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$5	100.0	$20	181.8

Wholesale revenues from sales to affiliated companies within the Southern Company system 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 second quarter 2014, wholesale revenues from affiliates were $10 million compared to $5 million in the corresponding period in 2013. The increase was due to higher demand resulting from warmer weather in 2014 as compared to the corresponding period in 2013 and the lower cost of Georgia Power-owned generation.

For year-to-date 2014, wholesale revenues from sales to affiliates were $31 million compared to $11 million for the corresponding period in 2013. The increase was due to higher demand resulting from colder weather in the first quarter 2014 and warmer weather in the second quarter 2014 as compared to the corresponding periods in 2013 and the lower cost of Georgia Power-owned generation.

Other Revenues

Second Quarter 2014 vs. Second Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$11	12.9	$15	8.8

In the second quarter 2014, other operating revenues were $96 million compared to $85 million in the corresponding period in 2013. For year-to-date 2014, other operating revenues were $185 million compared to $170 million in the corresponding period in 2013. The increases were due to increases of $3 million and $7 million in transmission revenues, $5 million and $5 million of solar application fee revenue, and $1 million and $2 million in outdoor lighting revenues for the second quarter and year-to-date 2014, respectively, as compared to the corresponding periods in 2013.

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GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Fuel and Purchased Power Expenses

	Second Quarter 2014 vs. Second Quarter 2013					Year-to-Date 2014 vs. Year-to-Date 2013
	(change in millions)			(% change)		(change in millions)			(% change)
Fuel	$	62		11.1		$	295		27.4
Purchased power – non-affiliates	2			3.3		31			27.9
Purchased power – affiliates	(10		)	(5.7	)	(1		)	(0.3	)
Total fuel and purchased power expenses	$	54				$	325

In the second quarter 2014, total fuel and purchased power expenses were $848 million compared to $794 million in the corresponding period in 2013. The increase in the second quarter 2014 was primarily due to a $65 million increase primarily in the volume of KWHs generated as a result of warmer weather driving higher customer demand and a $26 million increase in the average cost of purchased power primarily due to higher natural gas prices, partially offset by a $37 million decrease in the average cost of fuel primarily due to lower coal prices.

For year-to-date 2014, total fuel and purchased power expenseswere $1.86 billion compared to $1.54 billion in the corresponding period in 2013.The increase in year-to-date 2014 was primarily due toa $114 million increase in the average cost of fuel and purchased power primarily due to higher natural gas prices and a $211 million increase in the volume of KWHs generated primarily as a result of colder weather in the first quarter 2014 and warmer weather in the second quarter 2014 driving higher customer demand.

Fuel and purchased power energy transactions do not have a significant impact on earnings since these fuel expenses are generally offset by fuel revenues through Georgia Power's fuel cost recovery mechanism. See FUTURE EARNINGS POTENTIAL – "PSC Matters – Fuel Cost Recovery" herein for additional information.

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

	Second Quarter 2014	Second Quarter 2013	Year-to-Date 2014	Year-to-Date 2013
Total generation (billions of KWHs)	18	16	36	31
Total purchased power (billions of KWHs)	5	6	10	12
Sources of generation (percent) —
Coal	42	33	45	31
Nuclear	22	26	21	24
Gas	34	38	31	42
Hydro	2	3	3	3
Cost of fuel, generated (cents per net KWH) —
Coal	4.20	4.90	4.65	5.07
Nuclear	0.93	0.91	0.92	0.91
Gas	3.81	3.56	4.09	3.34
Average cost of fuel, generated (cents per net KWH)	3.32	3.32	3.66	3.30
Average cost of purchased power (cents per net KWH)(a)	5.55	5.02	5.66	4.72

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

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GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Fuel

In the second quarter 2014, fuel expense was $619 million compared to $557 million in the corresponding period in 2013. The increase was primarily due to an 11.8% increase in the volume of KWHs generated as a result of higher demand and a 7.0% increase in the average cost of natural gas per KWH generated, partially offset by a 14.3% decrease in the average cost of coal per KWH generated.

For year-to-date 2014, fuel expense was $1.37 billion compared to $1.08 billion in the corresponding period in 2013. The increase was primarily due toa 16.5% increase in the volume of KWHs generated as a result of higher demand and a 10.9% increase in the average cost of fuel per KWH generated primarily due to higher natural gas prices.

Purchased Power – Non-Affiliates

In the second quarter 2014, purchased power expense from non-affiliates was $63 million compared to $61 million in the corresponding period in 2013. The increase was due to a 24.1% increase in the average cost per KWH purchased, partially offset by an 18.0% decrease in the volume of KWHs purchased as the cost of Georgia Power-owned generation was lower than the market cost of available energy primarily due to higher natural gas prices.

For year-to-date 2014, purchased power expense from non-affiliates was $142 million compared to $111 million in the corresponding period in 2013.The increase was due toan increase of 27.9% in the average cost per KWH purchased, partially offset by a 0.5% decrease in the volume of KWHs purchased as the cost of Georgia Power-owned generation was lower than the market cost of available energy primarily due to higher natural gas prices.

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

Purchased Power – Affiliates

In the second quarter 2014, purchased power expense from affiliates was $166 million compared to $176 million in the corresponding period in 2013. The decrease was due to a 10.4% decrease in the volume of KWHs purchased, as Georgia Power units generally dispatched at a lower cost than other Southern Company system resources, partially offset by a 7.7% increase in the average cost per KWH purchased reflecting higher natural gas prices.

For year-to-date 2014, purchased power expense from affiliates was $350 million compared to $351 million in the corresponding period in 2013. The decrease was primarily due to a 12.4% decrease in the volume of KWHs purchased, as Georgia Power units generally dispatched at a lower cost than other Southern Company system resources, partially offset by a 15.3% increase in the average cost per KWH purchased reflecting higher natural gas prices.

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.

Other Operations and Maintenance Expenses

Second Quarter 2014 vs. Second Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$54	13.6	$50	6.0

In the second quarter 2014, other operations and maintenance expenses were $451 million compared to $397 million in the corresponding period in 2013. The increase was primarily due to increases of $19 million in generation expenses to meet higher demand and for scheduled outage maintenance, $16 million in transmission and distribution overhead line maintenance, $9 million in customer assistance expenses related to customer incentive

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

and demand-side management programs, $3 million in litigation expense, and $3 million in the storm damage accrual as authorized in the 2013 ARP.

For year-to-date 2014, other operations and maintenance expenses were $878 million compared to $828 million in the corresponding period in 2013. The increase was due toincreases of $25 million in generation expenses to meet higher demand, $15 million in transmission and distribution overhead line maintenance, $9 million in customer assistance expenses related to customer incentive and demand-side management programs, and $10 million in litigation expense, partially offset by a $6 million net decrease in employee compensation and benefits including pension.

Depreciation and Amortization

Second Quarter 2014 vs. Second Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$5	2.5	$13	3.2

In the second quarter 2014, depreciation and amortization was $209 million compared to $204 million in the corresponding period in 2013. The increase was due to a decrease of $9 million reflecting the completion of amortization related to state income tax credits in December 2013 and a decrease of $4 million in amortization of other cost of removal obligations as authorized in the 2013 ARP, partially offset by a decrease of $7 million in depreciation and amortization also as authorized in the 2013 ARP.

For year-to-date 2014, depreciation and amortizationwas $417 million compared to $404 million in the corresponding period in 2013. Theincrease was primarily due toa decrease of $18 million reflecting the completion of amortization related to state income tax credits in December 2013 and a decrease of $8 million in amortization of other cost of removal obligations as authorized in the 2013 ARP, partially offset by a decrease of $14 million in depreciation and amortization also as authorized in the 2013 ARP.

Taxes Other Than Income Taxes

Second Quarter 2014 vs. Second Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$11	11.6	$19	10.0

In the second quarter 2014, taxes other than income taxes were $106 million compared to $95 million in the corresponding period in 2013. For year-to-date 2014,taxes other than income taxes were $209 millioncompared to $190 million in the corresponding period in 2013.The increases were primarily due to increases of $8 million and $16 million in municipal franchise fees related to higher retail revenues in the second quarter 2014 and year-to-date 2014, respectively.

Interest Expense, Net of Amounts Capitalized

Second Quarter 2014 vs. Second Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$(6)	(6.3)	$(13)	(7.0)

In the second quarter 2014, interest expense, net of amounts capitalized was $90 million compared to $96 million in the corresponding period in 2013. The decrease was due to a $13 million decrease in interest on long-term debt resulting from the refinancing of long-term debt at lower rates and redemptions, partially offset by $9 million in interest on borrowings from the FFB.

For year-to-date 2014, interest expense, net of amounts capitalized was $174 million compared to $187 million in the corresponding period in 2013. The decrease was due to a $23 million decrease in interest on long-term debt

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

resulting from the refinancing of long-term debt at lower rates and redemptions, partially offset by $13 million in interest on borrowings from 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.

Income Taxes

Second Quarter 2014 vs. Second Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$—	—	$42	14.0

In the second quarters 2014 and 2013, income taxes were $177 million. An increase in income taxes due to higher pre-tax earnings was offset by the recognition of tax benefits primarily related to emission allowances and state apportionment in the second quarter 2014 as compared to the corresponding period in 2013.

For year-to-date 2014, income taxes were $343 million compared to $301 million in the corresponding period in 2013. The increase in year-to-date 2014 was primarily due to higher pre-tax earnings as compared to the corresponding period in 2013.

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 is subject to a number of factors. These factors include weather, competition, new energy contracts with other utilities, energy conservation practiced 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.

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 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.

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GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Environmental Statutes and Regulations

Air Quality

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Air Quality" of Georgia Power in Item 7 of the Form 10-K for additional information regarding the Cross State Air Pollution Rule (CSAPR) and the EPA's proposed rules regarding the regulation of excess emissions during periods of startup, shutdown, or malfunction (SSM).

On April 29, 2014, the U.S. Supreme Court overturned the U.S. Court of Appeals for the District of Columbia Circuit's August 2012 decision to vacate CSAPR and remanded the case back to the U.S. Court of Appeals for the District of Columbia Circuit for further proceedings. On June 26, 2014, the EPA requested that the U.S. Court of Appeals for the District of Columbia Circuit lift the stay on CSAPR and approve a revised schedule with compliance to begin on January 1, 2015.

On June 10, 2014, the EPA entered into a revised settlement agreement requiring it to issue a supplemental proposed SSM rule by September 5, 2014 and finalize the proposed rule by May 22, 2015.

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

Water Quality

On April 21, 2014, the EPA and the U.S. Army Corps of Engineers jointly published a proposed rule to revise the regulatory definition of waters of the U.S. for all Clean Water Act (CWA) programs, significantly expanding the scope of federal jurisdiction under the CWA. If finalized as proposed, this rule could significantly increase permitting and regulatory requirements and costs associated with the siting of new facilities and the installation, expansion, and maintenance of transmission and distribution lines. In addition, the rule as proposed could have significant impacts on economic development projects which could affect customer demand growth. The ultimate impact of the proposed rule will depend on the specific requirements of the final rule and the outcome of any legal challenges and cannot be determined at this time.

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Water Quality" of Georgia Power in Item 7 of the Form 10-K for additional information regarding the EPA's rulemaking for cooling water intake structures.

On May 19, 2014, the EPA signed a final rule establishing standards for reducing effects on fish and other aquatic life caused by new and existing cooling water intake structures at existing power plants and manufacturing facilities. The ultimate outcome of this final rule will depend on the results of additional studies and implementation of the rule by state regulators, but could result in additional capital and operational costs associated with changes to existing intake structures and cooling systems and increased costs associated with the construction of new generating units. The ultimate impact of this rule will depend on the outcome of any legal challenges and cannot be determined at this time.

Global Climate Issues

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues" of Georgia Power in Item 7 of the Form 10-K for additional information regarding the EPA's current and proposed regulation of GHG emissions under the Clean Air Act.

On June 18, 2014, the EPA published the proposed Clean Power Plan, setting forth guidelines for states to develop plans to address CO₂ emissions from existing fossil fuel-fired electric generating units. The EPA's proposed guidelines establish state-specific interim and final CO₂ emission rate goals to be achieved between 2020 and 2029 and in 2030 and thereafter. The EPA also published the proposed CO₂ performance standards for modified and reconstructed fossil fuel-fired electric generating units. If finalized as proposed, the proposed guidelines and standards could result in operational restrictions and material compliance costs, including capital expenditures, that could impact unit retirement and replacement decisions. Also, additional compliance costs could affect results of

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

operations, cash flows, and financial condition if such costs are not recovered through regulated rates. Further, any resulting higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively impact results of operations, cash flows, and financial condition. The ultimate impact of these proposals will depend on the specific requirements of the final guidelines and performance standards, implementation by states, and the outcome of any legal challenges and cannot be determined at this time.

On June 23, 2014, the U.S. Supreme Court struck down a portion of the EPA's program for GHG permitting under the Prevention of Significant Deterioration and Title V operating permit programs, holding that a facility's GHG emissions alone could not trigger a requirement to obtain a permit and that the EPA did not have the authority to tailor the statutory permitting thresholds. The ultimate impact of this decision cannot be determined at this time.

PSC Matters

Renewables Development

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Renewables Development" of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Renewables Development" in Item 8 of the Form 10-K for additional information.

On May 20, 2014, the Georgia PSC approved Georgia Power's application for the certification of two PPAs executed in April 2013 for the purchase of energy from two wind farms in Oklahoma with capacity totaling 250 MWs that will begin in 2016 and end in 2035.

As a result of biomass PPA amendments executed during the second and third quarters of 2014, contractual obligations related to PPAs decreased $491 million from December 31, 2013. Estimated purchased power contractual obligations have been updated to $661million for 2015 and 2016, $670 million for 2017 and 2018, and $3.7 billion after 2018. Estimated purchased power contractual obligations did not change for 2014. The counterparties of the aforementioned PPAs have posted collateral as required. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations – Contractual Obligations" of Georgia Power in Item 7 of the Form 10-K for additional information.

Integrated Resource Plan

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Integrated Resource Plans" of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Integrated Resource Plans" in Item 8 of the Form 10-K for additional information.

Georgia Power filed a request with the Georgia PSC on January 10, 2014 to cancel the proposed biomass fuel conversion of Plant Mitchell Unit 3 (155 MWs) because it would not be cost effective for customers. On July 1, 2014, the Georgia PSC approved Georgia Power's request. The January 10, 2014 filing also notified the Georgia PSC of Georgia Power's plan to seek decertification later this year. Georgia Power now expects to request decertification of Plant Mitchell Unit 3 in connection with the triennial Integrated Resource Plan in 2016. Georgia Power plans to continue to operate the unit as needed until the Mercury and Air Toxics Standards rule becomes effective in April 2015.

Fuel Cost Recovery

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Fuel Cost Recovery" of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information.

As of June 30, 2014, Georgia Power's under recovered fuel balance totaled $244 million and is included in deferred charges and other assets on Georgia Power's Condensed Balance Sheet herein. The under recovered fuel balance

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exceeded the $200 million threshold, triggering the Interim Fuel Rider mechanism. Therefore, on July 7, 2014, Georgia Power filed a plan with the Georgia PSC recommending that the Georgia PSC defer any action on the under recovered fuel balance until the next fuel case which is expected to be filed by February 27, 2015. The Georgia PSC took no action on Georgia Power's filing within 30 days; therefore, the existing fuel rates remain in place. As of December 31, 2013, Georgia Power's over recovered fuel balance totaled $58 million and is included in current liabilities and other deferred credits and liabilities on Georgia Power's Condensed Balance Sheet herein.

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.

Storm Damage Recovery

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Storm Damage Recovery" of Georgia Power in Item 7 and Note 1 to the financial statements of Georgia Power under "Storm Damage Recovery" in Item 8 of the Form 10-K for additional information.

Georgia Power defers and recovers certain costs related to damages from major storms as mandated by the Georgia PSC. As of June 30, 2014 and December 31, 2013, the balance in the regulatory asset related to storm damage was $107 million and $37 million, respectively. The increase was primarily the result of an ice storm in February 2014. As a result of the regulatory treatment, costs related to storms are generally not expected to have a material impact on Georgia Power's financial statements.

Nuclear Construction

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC 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, the eighth Vogtle Construction Monitoring (VCM) report, the ninth/tenth VCM report, and pending litigation.

In 2009, the Georgia PSC approved inclusion of the Plant Vogtle Units 3 and 4 related CWIP accounts in rate base, and the State of Georgia enacted the Georgia Nuclear Energy Financing Act, which allows Georgia Power to recover financing costs for nuclear construction projects certified by the Georgia PSC. Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff by including the related CWIP accounts in rate base during the construction period. The Georgia PSC approved increases to the NCCR tariff of approximately $223 million, $35 million, $50 million, and $60 million, effective January 1, 2011, 2012, 2013, and 2014, respectively. Through the NCCR tariff, Georgia Power is collecting and amortizing to earnings approximately $91 million of financing costs, capitalized in 2009 and 2010, over the five-year period ending December 31, 2015, in addition to the ongoing financing costs. At June 30, 2014, approximately $27 million of these 2009 and 2010 costs remained unamortized in CWIP.

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. Accordingly, Georgia Power's eighth VCM report filed in February 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 September 2013, the Georgia PSC approved a 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

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Vogtle Unit 3, or earlier if deemed appropriate by the Georgia PSC and Georgia Power. In accordance with the Georgia Integrated Resource Planning Act, any costs incurred by Georgia Power in excess of the certified amount will not be included in rate base, unless shown to be reasonable and prudent. In addition, financing costs on any excess construction-related costs potentially would be subject to recovery through AFUDC instead of the NCCR tariff. In accordance with the stipulation, Georgia Power filed with the Georgia PSC on February 28, 2014 a combined ninth and tenth VCM report covering the period from January 1 through December 31, 2013 (Ninth/Tenth VCM report), which requested approval for an additional $0.4 billion of construction capital costs. The Ninth/Tenth VCM report reflects estimated in-service construction capital costs of $4.8 billion and associated financing costs during the construction period, which are estimated to total approximately $2.0 billion. Georgia Power will resume filing semi-annual reports with the eleventh VCM report filing in late August 2014.

In 2012, the Owners and the Contractor began negotiations regarding the costs associated with design changes to the Westinghouse Design Control Document, as amended (DCD), and the delays in the timing of approval of the DCD and issuance of the combined construction and operating licenses (COLs), including the assertion by the Contractor that the Owners are responsible for these costs under the terms of the agreement entered into by Georgia Power, acting for itself and as agent for the Owners, and the Contractor, pursuant to which the Contractor agreed to design, engineer, procure, construct, and test Plant Vogtle Units 3 and 4 (Vogtle 3 and 4 Agreement). Also in 2012, Georgia Power and the other Owners filed suit against the Contractor in the U.S. District Court for the Southern District of Georgia seeking a declaratory judgment that the Owners are not responsible for these costs. Later in 2012, the Contractor filed suit against Georgia Power and the other Owners in the U.S. District Court for the District of Columbia alleging the Owners are responsible for these costs. In August 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. The Contractor appealed the decision to the U.S. Court of Appeals for the District of Columbia Circuit in September 2013. 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 has asserted it is entitled to further schedule extensions. On May 22, 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 have 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 claimed amounts relating to these new allegations, but such additional claimed amounts could be substantial. Georgia Power has not agreed with either the proposed cost or schedule adjustments or that the Owners have any responsibility for costs related to these issues. While litigation is ongoing and Georgia Power intends to vigorously defend its positions, Georgia Power also expects negotiations with the Contractor to continue with respect to cost and schedule during which negotiations the parties may reach a mutually acceptable compromise of their positions.

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 Owners or the Contractor or to both.

As construction continues, the risk remains that additional challenges in the 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. Additional claims by the Contractor or Georgia Power (on behalf of the 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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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 increased generally throughout the U.S. In particular, personal injury, property damage, and other claims for damages alleged to have been caused by CO₂ and other emissions, coal combustion residuals, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters, have become more frequent.

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 the Notes 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.

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Other Matters" of Georgia Power in Item 7 of the Form 10-K for additional information regarding the NRC's performance of additional operational and safety reviews of nuclear facilities in the U.S. following the major earthquake and tsunami that struck Japan in 2011.

Additionally, there are 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 events cannot be determined at this time.

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Other Matters" of Georgia Power in Item 7 of the Form 10-K for additional information regarding the court order for the DOE to set the spent fuel depositary fees at zero. On March 18, 2014, the U.S. Court of Appeals for the District of Columbia Circuit denied the DOE's request for rehearing of the November 2013 panel decision ordering that the DOE propose the nuclear waste fund fee be changed to zero. The DOE formally set the fee to zero effective May 16, 2014. On June 17, 2014, the Georgia PSC approved Georgia Power's request to credit customers the portion of fuel cost related to the nuclear waste fund fee. The nuclear waste fund rider was implemented July 1, 2014. The ultimate outcome of this matter cannot be determined at this time.

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

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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

On May 28, 2014, the Financial Accounting Standards Board issued ASC 606, Revenue from Contracts with Customers. ASC 606 revises the accounting for revenue recognition and is effective for fiscal years beginning after December 15, 2016. Georgia Power is currently evaluating the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined.

FINANCIAL CONDITION AND LIQUIDITY

Overview

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Georgia Power in Item 7 of the Form 10-K for additional information. Georgia Power's financial condition remained stable at June 30, 2014. Georgia Power intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.

Net cash provided from operating activities totaled $843 million for the first six months of 2014 compared to $931 million for the corresponding period in 2013. The decrease was primarily due to fuel cost recovery and storm restoration costs, partially offset by higher retail operating revenues and lower fuel inventory additions. Net cash used for investing activities totaled $917 million for the first six months of 2014 compared to $807 million for the corresponding period in 2013 due to gross property additions primarily related to installation of equipment to comply with environmental standards; construction of transmission and distribution facilities; and purchase of nuclear fuel. Net cash provided from financing activities totaled $90 million for the first six months of 2014 compared to $140 million used for financing activities in the corresponding period in 2013. The increase in cash provided from financing activities is primarily due to borrowings from the FFB for the construction of Plant Vogtle Units 3 and 4, partially offset by FFB loan issuance costs and a reduction in short-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 six months of 2014 include increases of $546 million in property, plant, and equipment, $961 million in long-term debt primarily due to borrowings from the FFB, and $244 million in under recovered regulatory clause revenues and decreases of $358 million in short-term debt and $255 million in fossil fuel stock.

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 $5 million will be required through June 30, 2015 to fund maturities of long-term debt.

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

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cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. See Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Nuclear Construction" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" herein for information regarding additional factors that may impact construction expenditures.

Sources of Capital

Except as described below with respect to the DOE loan guarantees, Georgia Power plans to obtain the funds required for construction and other purposes from sources similar to those used in the past, which were primarily from operating cash flows, short-term debt, 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.

On February 20, 2014, Georgia Power and the DOE entered into a loan guarantee agreement (Loan Guarantee Agreement), pursuant to which the DOE agreed to guarantee borrowings to be made by Georgia Power under a multi-advance credit facility (FFB Credit Facility) among Georgia Power, the DOE, and the FFB. Georgia Power is obligated to reimburse the DOE for any payments the DOE is required to make to the FFB under the guarantee. Georgia Power's reimbursement obligations to the DOE are secured by a first priority lien on (i) Georgia Power's 45.7% ownership interest in Plant Vogtle Units 3 and 4 (primarily the units under construction, the related real property, and any nuclear fuel loaded in the reactor core) and (ii) Georgia Power's rights and obligations under the principal contracts relating to Plant Vogtle Units 3 and 4. Under the FFB Credit Facility, Georgia Power may make term loan borrowings through the FFB. Proceeds of borrowings made under the FFB Credit Facility will be used to reimburse Georgia Power for a portion of certain costs of construction relating to Plant Vogtle Units 3 and 4 that are eligible for financing under the Loan Guarantee Agreement (Eligible Project Costs). Aggregate borrowings under the FFB Credit Facility may not exceed the lesser of (i) 70% of Eligible Project Costs or (ii) approximately $3.46 billion. See Note 6 to the financial statements of Georgia Power 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 June 30, 2014 would allow for borrowings of up to $1.9 billion under the FFB Credit Facility. Through June 30, 2014, Georgia Power has borrowed $1.0 billion under the FFB Credit Facility, leaving $0.9 billion of currently available borrowing ability.

Georgia 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. Georgia Power has substantial cash flow from operating activities and access to the capital markets to meet liquidity needs.

At June 30, 2014, Georgia Power had approximately $46 million of cash and cash equivalents. Committed credit arrangements with banks at June 30, 2014 were as follows:

Expires(a)
	2016		2018		Total		Unused
(in millions)					(in millions)
	$	150	$	1,600	$	1,750	$	1,736

(a) No credit arrangements expire in 2014, 2015, or 2017.

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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 borrowings. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of June 30, 2014 was approximately $825 million. Subsequent to June 30, 2014, an additional $40 million of variable rate pollution control revenue bonds, previously purchased and held by Georgia Power, were remarketed to the public and currently require liquidity support. In addition, at June 30, 2014, Georgia Power had $150 million of fixed rate pollution control revenue bonds that were required to be remarketed within the next 12 months. Subsequent to June 30, 2014, $45 million of these fixed rate pollution control revenue bonds were remarketed to the public and currently are not required to be remarketed within the next 12 months. In addition, all or a portion of approximately $108 million of certain pollution control bonds are being evaluated for redemption in connection with unit retirement and fuel conversion decisions. See Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Integrated Resource Plans" in Item 8 of the Form 10-K for additional information.

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 arrangements contain material adverse change clauses at the time of borrowings. Georgia Power expects to renew 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 June 30, 2014			Short-term Debt During the Period(a)
	Amount Outstanding		Weighted Average Interest Rate	Average Outstanding		Weighted Average Interest Rate	Maximum Amount Outstanding
	(in millions)			(in millions)			(in millions)
Commercial paper	$	689	0.2%	$	356	0.2%	$	703

(a) Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 2014.

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

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, and construction of new generation. The maximum potential collateral requirements under these contracts at June 30, 2014 were as follows:

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Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB- and/or Baa3	$	88
Below BBB- and/or Baa3	1,246

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 Georgia 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 February 2014, Georgia Power made initial borrowings under the FFB Credit Facility in an aggregate principal amount of $1.0 billion. The interest rate applicable to $500 million of the initial advance under the FFB Credit Facility is 3.860% for an interest period that extends to February 20, 2044 (the final maturity date) and the interest rate applicable to the remaining $500 million is 3.488% for an interest period that extends to February 20, 2029 and is expected to be reset from time to time thereafter through the final maturity date. The final maturity date for all advances under the FFB Credit Facility is February 20, 2044. The proceeds of the initial borrowings under the FFB Credit Facility were used to reimburse Georgia Power for Eligible Project Costs relating to the construction of Plant Vogtle Units 3 and 4. Under the Loan Guarantee Agreement, Georgia Power is subject to customary events of default, as well as cross-defaults to other indebtedness and events of default relating to any failure to make payments under the engineering, procurement, and construction contract, as amended, relating to Plant Vogtle Units 3 and 4 or certain other agreements providing intellectual property rights for Plant Vogtle Units 3 and 4. The Loan Guarantee Agreement also includes events of default specific to the DOE loan guarantee program, including the failure of Georgia Power or Southern Nuclear to comply with requirements of law or DOE loan guarantee program requirements. See Note 6 to the financial statements of Georgia Power in Item 8 of the Form 10-K under "DOE Loan Guarantee Borrowings" for additional information.

In February 2014, Georgia Power repaid three four-month floating rate bank loans in an aggregate principal amount of $400 million.

In June 2014, Georgia Power redeemed $17 million aggregate principal amount of Development Authority of Bartow County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Bowen Project), Second Series 1998 and $19.5 million aggregate principal amount of Development Authority of Appling County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Hatch Project), Second Series 2001.

Subsequent to June 30, 2014, Georgia Power reoffered to the public $40 million aggregate principal amount of Development Authority of Monroe County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Scherer Project), First Series 2009, which had been previously purchased and held by Georgia Power since 2010.

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

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GULF POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2014			2013			2014			2013
	(in thousands)						(in thousands)
Operating Revenues:
Retail revenues	$	310,344		$	305,550		$	613,464		$	565,427
Wholesale revenues, non-affiliates	34,335			31,894			69,927			53,102
Wholesale revenues, affiliates	23,627			19,050			76,405			48,505
Other revenues	15,225			14,679			30,867			30,413
Total operating revenues	383,531			371,173			790,663			697,447
Operating Expenses:
Fuel	145,244			140,347			313,666			261,193
Purchased power, non-affiliates	14,331			13,054			29,792			24,189
Purchased power, affiliates	9,184			10,934			15,688			14,246
Other operations and maintenance	81,127			76,846			165,328			155,508
Depreciation and amortization	39,010			37,081			70,867			74,134
Taxes other than income taxes	25,758			23,760			52,557			47,386
Total operating expenses	314,654			302,022			647,898			576,656
Operating Income	68,877			69,151			142,765			120,791
Other Income and (Expense):
Allowance for equity funds used during construction	2,702			1,521			5,081			2,655
Interest expense, net of amounts capitalized	(13,294		)	(14,293		)	(26,558		)	(28,662		)
Other income (expense), net	(505		)	(1,391		)	(1,230		)	(2,367		)
Total other income and (expense)	(11,097		)	(14,163		)	(22,707		)	(28,374		)
Earnings Before Income Taxes	57,780			54,988			120,058			92,417
Income taxes	21,433			20,755			44,717			34,841
Net Income	36,347			34,233			75,341			57,576
Dividends on Preference Stock	2,250			1,651			4,501			3,202
Net Income After Dividends on Preference Stock	$	34,097		$	32,582		$	70,840		$	54,374

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2014		2013		2014		2013
	(in thousands)				(in thousands)
Net Income	$	36,347	$	34,233	$	75,341	$	57,576
Other comprehensive income (loss):
Qualifying hedges:
Reclassification adjustment for amounts included in net income, net of tax of $59, $90, $117 and $180, respectively	93		143		186		286
Total other comprehensive income (loss)	93		143		186		286
Comprehensive Income	$	36,440	$	34,376	$	75,527	$	57,862

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

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GULF POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Six Months Ended June 30,
	2014			2013
	(in thousands)
Operating Activities:
Net income	$	75,341		$	57,576
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	74,689			77,627
Deferred income taxes	19,627			36,407
Allowance for equity funds used during construction	(5,081		)	(2,655		)
Pension, postretirement, and other employee benefits	2,851			5,452
Stock based compensation expense	1,111			1,028
Other, net	(3,396		)	2,209
Changes in certain current assets and liabilities —
-Receivables	(56,873		)	(59,770		)
-Prepayments	1,463			1,271
-Fossil fuel stock	39,187			19,332
-Materials and supplies	1,170			(987		)
-Prepaid income taxes	9,289			(2,822		)
-Other current assets	(1,024		)	13
-Accounts payable	831			(9,703		)
-Accrued taxes	12,483			13,632
-Accrued compensation	(109		)	(8,308		)
-Over recovered regulatory clause revenues	9,129			(15,659		)
-Other current liabilities	(3,522		)	(1,199		)
Net cash provided from operating activities	177,166			113,444
Investing Activities:
Property additions	(158,863		)	(137,283		)
Cost of removal, net of salvage	(6,032		)	(7,010		)
Change in construction payables	(1,684		)	6,307
Payments pursuant to long-term service agreements	(3,953		)	(2,855		)
Other investing activities	46			120
Net cash used for investing activities	(170,486		)	(140,721		)
Financing Activities:
Increase in notes payable, net	2,702			1,230
Proceeds —
Common stock issued to parent	50,000			40,000
Capital contributions from parent company	2,268			1,419
Preference stock	—			50,000
Pollution control revenue bonds	42,075			63,000
Senior notes	—			90,000
Redemptions — Pollution control revenue bonds	(29,075		)	(63,000		)
Payment of preference stock dividends	(4,501		)	(3,101		)
Payment of common stock dividends	(61,600		)	(57,700		)
Other financing activities	(602		)	(3,105		)
Net cash provided from financing activities	1,267			118,743
Net Change in Cash and Cash Equivalents	7,947			91,466
Cash and Cash Equivalents at Beginning of Period	21,753			32,167
Cash and Cash Equivalents at End of Period	$	29,700		$	123,633
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $2,271 and $1,408 capitalized for 2014 and 2013, respectively)	$	25,860		$	26,987
Income taxes, net	16,712			428
Noncash transactions — accrued property additions at end of period	30,951			29,036

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

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Assets	At June 30, 2014			At December 31, 2013
	(in thousands)
Current Assets:
Cash and cash equivalents	$	29,700		$	21,753
Receivables —
Customer accounts receivable	83,332			64,884
Unbilled revenues	72,613			57,282
Under recovered regulatory clause revenues	66,343			48,282
Other accounts and notes receivable	11,814			8,620
Affiliated companies	10,600			8,259
Accumulated provision for uncollectible accounts	(1,295		)	(1,131		)
Fossil fuel stock, at average cost	95,864			135,050
Materials and supplies, at average cost	53,766			54,935
Other regulatory assets, current	16,567			18,536
Prepaid expenses	9,890			33,186
Other current assets	9,680			6,120
Total current assets	458,874			455,776
Property, Plant, and Equipment:
In service	4,434,802			4,363,664
Less accumulated provision for depreciation	1,252,856			1,211,336
Plant in service, net of depreciation	3,181,946			3,152,328
Construction work in progress	352,194			280,626
Total property, plant, and equipment	3,534,140			3,432,954
Other Property and Investments	15,169			15,314
Deferred Charges and Other Assets:
Deferred charges related to income taxes	53,436			50,597
Prepaid pension costs	11,604			11,533
Other regulatory assets, deferred	347,665			340,415
Other deferred charges and assets	41,492			30,982
Total deferred charges and other assets	454,197			433,527
Total Assets	$	4,462,380		$	4,337,571

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 June 30, 2014			At December 31, 2013
	(in thousands)
Current Liabilities:
Securities due within one year	$	75,000		$	75,000
Notes payable	138,580			135,878
Accounts payable —
Affiliated	78,005			76,897
Other	46,166			47,038
Customer deposits	34,849			34,433
Accrued taxes —
Accrued income taxes	45			45
Other accrued taxes	21,525			7,486
Accrued interest	8,490			10,272
Accrued compensation	11,549			11,657
Other regulatory liabilities, current	17,709			13,408
Liabilities from risk management activities	3,707			6,470
Other current liabilities	21,173			22,972
Total current liabilities	456,798			441,556
Long-term Debt	1,171,446			1,158,163
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	751,131			734,355
Accumulated deferred investment tax credits	3,419			4,055
Employee benefit obligations	76,504			76,338
Other cost of removal obligations	230,344			228,148
Other regulatory liabilities, deferred	57,117			56,051
Deferred capacity expense	196,059			180,149
Other deferred credits and liabilities	74,590			77,126
Total deferred credits and other liabilities	1,389,164			1,356,222
Total Liabilities	3,017,408			2,955,941
Preference Stock	146,504			146,504
Common Stockholder's Equity:
Common stock, without par value —
Authorized — 20,000,000 shares
Outstanding — June 30, 2014: 5,442,717 shares
— December 31, 2013: 4,942,717 shares	483,060			433,060
Paid-in capital	556,596			552,681
Retained earnings	259,735			250,494
Accumulated other comprehensive loss	(923		)	(1,109		)
Total common stockholder's equity	1,298,468			1,235,126
Total Liabilities and Stockholder's Equity	$	4,462,380		$	4,337,571

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

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SECOND QUARTER 2014 vs. SECOND QUARTER 2013

AND

YEAR-TO-DATE 2014 vs. YEAR-TO-DATE 2013

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 given economic conditions, 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

Second Quarter 2014 vs. Second Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$1.5	4.6	$16.4	30.3

Gulf Power's net income after dividends on preference stock for the second quarter 2014 was $34.1 million compared to $32.6 million for the corresponding period in 2013. The increase was primarily due to higher retail revenues related to a base rate increase, partially offset by higher non-fuel operations and maintenance expenses.

Gulf Power's net income after dividends on preference stock for year-to-date 2014 was $70.8 million compared to $54.4 million for the corresponding period in 2013. The increase was primarily due to higher retail revenues related to a base rate increase and colder weather in the first quarter 2014, partially offset by non-fuel operations and maintenance expenses.

Retail Revenues

Second Quarter 2014 vs. Second Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$4.7	1.6	$48.1	8.5

In the second quarter 2014, retail revenues were $310.3 million compared to $305.6 million for the corresponding period in 2013. For year-to-date 2014, retail revenues were $613.5 million compared to $565.4 million for the corresponding period in 2013.

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Details of the changes in retail revenues were as follows:

	Second Quarter 2014					Year-to-Date  2014
	(in millions)			(% change)		(in millions)		(% change)
Retail – prior year	$	305.6				$	565.4
Estimated change resulting from –
Rates and pricing	11.0			3.6		22.7		4.0
Sales growth (decline)	(0.6		)	(0.2	)	1.6		0.3
Weather	1.5			0.5		10.9		2.0
Fuel and other cost recovery	(7.2		)	(2.3	)	12.9		2.2
Retail – current year	$	310.3		1.6	%	$	613.5	8.5	%

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

Revenues associated with changes in rates and pricing increased in the second quarter and year-to-date 2014 when compared to the corresponding periods in 2013 primarily due to an increase in retail base revenues resulting from the retail base rate increase effective January 2014 and higher revenues associated with an increase in the environmental cost recovery clause rate.

Revenues attributable to changes in sales decreased in the second quarter 2014 when compared to the corresponding period in 2013. Weather-adjusted KWH energy sales to residential and commercial customers decreased 2.3% and 1.2%, respectively, due to a decline in weather-adjusted use per customer, partially offset by customer growth. KWH energy sales to industrial customers increased 15.6% primarily due to decreased customer co-generation.

Revenues attributable to changes in sales increased year-to-date 2014 when compared to the corresponding period in 2013. Weather-adjusted KWH energy sales to residential and commercial customers decreased 0.8% and 1.1%, respectively, primarily due to a decline in weather-adjusted use per customer, partially offset by customer growth. KWH energy sales to industrial customers increased 14.0% primarily due to decreased customer co-generation.

Fuel and other cost recovery revenues decreased in the second quarter 2014 when compared to the corresponding period in 2013 primarily due to lower revenues associated with lower recoverable costs under Gulf Power's energy conservation and environmental cost recovery clauses. For year-to-date 2014, fuel and other cost recovery revenues increased when compared to the corresponding period in 2013 primarily due to higher revenues associated with recoverable fuel costs for increased generation and purchased power costs.

Fuel and other cost recovery provisions include fuel expenses, the energy component of purchased power costs, purchased power capacity costs, and the difference between projected and actual costs and revenues related to energy conservation and environmental compliance. See FUTURE EARNINGS POTENTIAL – "PSC Matters – Cost Recovery Clauses – Fuel Cost Recovery" of Gulf Power in Item 7 of the Form 10-K for additional information.

Wholesale Revenues – Non-Affiliates

Second Quarter 2014 vs. Second Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$2.4	7.7	$16.8	31.7

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

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

In the second quarter 2014, wholesale revenues from sales to non-affiliates were $34.3 million compared to $31.9 million for the corresponding period in 2013. The increase was primarily due to higher energy revenues related to an 11.7% increase in KWH sales.

For year-to-date 2014, wholesale revenues from sales to non-affiliates were $69.9 million compared to $53.1 million for the corresponding period in 2013. The increase was primarily due tohigher energy revenues related to an 85.8% increase in KWH sales due to lower-priced energy supply alternatives from the Southern Company system's resources and a planned outage at Plant Scherer Unit 3 in early 2013.

Wholesale Revenues – Affiliates

Second Quarter 2014 vs. Second Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$4.6	24.0	$27.9	57.5

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

In the second quarter 2014, wholesale revenues from sales to affiliates were $23.6 million compared to $19.0 million for the corresponding period in 2013. The increase was primarily due to a 14.3% increase in KWH sales that resulted from an increase of Gulf Power's generation utilized to serve affiliated companies' energy demand and an 8.6% increase in the price of energy sold to affiliates due to higher marginal generation costs.

For year-to-date 2014, wholesale revenues from sales to affiliates were $76.4 million compared to $48.5 million for the corresponding period in 2013. The increase was primarily due to a 35.6% increase in the price of energy sold to affiliates due to higher marginal generation costs and a 16.2% increase in KWH sales resulting from Gulf Power's generation being dispatched to serve affiliated companies' higher weather-related energy demand in 2014.

Fuel and Purchased Power Expenses

	Second Quarter 2014 vs. Second Quarter 2013					Year-to-Date 2014 vs. Year-to-Date 2013
	(change in millions)			(% change)		(change in millions)		(% change)
Fuel	$	4.9		3.5		$	52.5	20.1
Purchased power – non-affiliates	1.3			9.8		5.6		23.2
Purchased power – affiliates	(1.8		)	(16.0	)	1.4		10.1
Total fuel and purchased power expenses	$	4.4				$	59.5

In the second quarter 2014, total fuel and purchased power expenses were $168.7 million compared to $164.3 million for the corresponding period in 2013. The increase was primarily due to an $8.2 million increase in the volume of KWHs generated and purchased as a result of higher retail sales. This increase was partially offset by a $3.8 million decrease due to the lower average cost of fuel and purchased power.

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For year-to-date 2014, total fuel and purchased power expenses were $359.1 million compared to $299.6 million for the corresponding period in 2013. The increase was primarily due to a $50.2 million increase in the volume of KWHs generated and purchased as a result of colder weather in the first quarter 2014 increasing customer demand and a $9.3 million increase due to the higher 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 – Fuel Cost Recovery" and " – Purchased Power Capacity Recovery" of Gulf Power in Item 8 of the Form 10-K for additional information.

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

	Second Quarter 2014	Second Quarter 2013	Year-to-Date 2014	Year-to-Date 2013
Total generation (millions of KWHs)	2,670	2,424	5,632	4,285
Total purchased power (millions of KWHs)	1,281	1,346	2,711	3,009
Sources of generation (percent) –
Coal	69	68	70	61
Gas	31	32	30	39
Cost of fuel, generated (cents per net KWH) –
Coal(a)	4.09	4.52	4.21	4.58
Gas	3.99	4.28	3.82	3.98
Average cost of fuel, generated (cents per net KWH)	4.06	4.44	4.09	4.35
Average cost of purchased power (cents per net KWH)(a)	4.71	4.20	4.75	3.77

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

Fuel

In the second quarter 2014, fuel expense was $145.2 million compared to $140.3 million for the corresponding period in 2013. The increase was primarily due to a 10.1% increase in the volume of KWHs generated due to higher system loads in the second quarter 2014. The increase was partially offset by an 8.6% decrease in the average cost of fuel primarily due to lower-priced coal supply.

For year-to-date 2014, fuel expense was $313.7 million compared to $261.2 million for the corresponding period in 2013. The increase was primarily due to a 31.4% increase in the volume of KWHs generated due to higher system loads. The increase was partially offset by a 6.0% decrease in the average cost of fuel primarily due to lower-priced coal supply.

Purchased Power – Non-Affiliates

In the second quarter 2014, purchased power expense from non-affiliates was $14.4 million compared to $13.1 million for the corresponding period in 2013. The increase was primarily due to a 23.8% increase in the average cost per KWH purchased, which included a $3.1 million increase in capacity costs primarily associated with a scheduled increase from an existing PPA, partially offset by the expiration of another PPA. The increase was partially offset by an 8.6% decrease in the volume of KWHs purchased due to increased generation from Gulf Power's units.

For year-to-date 2014, purchased power expense from non-affiliates was $29.8 million compared to $24.2 million for the corresponding period in 2013. The increase was primarily due to a 36.8% increase in the average cost per KWH purchased, which included a $3.1 million increase in capacity costs primarily associated with a scheduled increase from an existing PPA, partially offset by the expiration of another PPA. This increase was partially offset

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by a 16.0% decrease in the volume of KWHs purchased due to colder regional weather conditions in the first quarter 2014 which limited the availability of market resources.

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

Purchased Power – Affiliates

In the second quarter 2014, purchased power expense from affiliates was $9.1 million compared to $10.9 million for the corresponding period in 2013. The decrease was primarily due to a 29.5% decrease in the average cost per KWH purchased, which included a $3.0 million reduction in capacity costs primarily associated with the expiration of an existing PPA, partially offset by a 15.0% increase in the volume of KWHs purchased due to higher off-system sales obligations.

For year-to-date 2014, purchased power expense from affiliates was $15.6 million compared to $14.2 million for the corresponding period in 2013. The increase was primarily due to a 50.8% increase in the volume of KWHs purchased due to colder weather driving higher demand in the first quarter 2014 compared to the corresponding period in 2013, partially offset by a 29.5% decrease in the average cost per KWH purchased, which included a $3.6 million reduction in capacity costs primarily associated with the expiration of an existing PPA.

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

Other Operations and Maintenance Expenses

Second Quarter 2014 vs. Second Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$4.2	5.6	$9.8	6.3

In the second quarter 2014, other operations and maintenance expenses were $81.1 million compared to $76.9 million for the corresponding period in 2013. The increase was primarily due to increases of $2.7 million in labor and benefit-related expenses, $1.4 million in customer uncollectibles and collection expenses, and $0.9 million in transmission service related to a third party PPA, partially offset by a decrease of $2.3 million in marketing programs.

For year-to-date 2014, other operations and maintenance expenses were $165.3 million compared to $155.5 million for the corresponding period in 2013. The increase was primarily due to increases of $9.3 million in routine and planned maintenance expenses at generation, transmission, and distribution facilities, $2.6 million in labor and benefit-related expenses, $1.7 million in transmission service related to a third party PPA, and $1.6 million in customer uncollectibles and collection expenses. These increases were partially offset by decreases of $3.5 million in marketing programs and $1.9 million in other energy services expenses.

The increased expense from transmission service did not have a significant impact on income since the expense was offset by purchased power capacity revenues through Gulf Power's purchased power capacity recovery clause. The decreased expense from marketing programs did not have a significant impact on income since the expense was offset by energy conservation revenues through Gulf Power's energy conservation cost recovery clause. The decreased expense from other energy services did not have a significant impact on income since the expense was generally offset by associated revenues. See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses – Energy Conservation Cost Recovery" in Item 8 of the Form 10-K for additional information.

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Depreciation and Amortization

Second Quarter 2014 vs. Second Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$1.9	5.2	$(3.3)	(4.4)

In the second quarter 2014, depreciation and amortization was $39.0 million compared to $37.1 million for the corresponding period in 2013. For year-to-date 2014, depreciation and amortization was $70.8 million compared to $74.1 million for the corresponding period in 2013. Additions at generation, transmission, and distribution facilities attributed to increases in depreciation and amortization of $1.1 million in the second quarter 2014 and $2.1 million year-to-date 2014. As approved by the Florida PSC in a 2013 rate order, Gulf Power may record a reduction in depreciation in an amount necessary to reach the midpoint of the authorized ROE range. Gulf Power recognized a $5.4 million reduction in depreciation expense in the first six months of 2014.

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

Taxes Other Than Income Taxes

Second Quarter 2014 vs. Second Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$2.0	8.4	$5.2	10.9

In the second quarter 2014, taxes other than income taxes were $25.8 million compared to $23.8 million for the corresponding period in 2013. For year-to-date 2014, taxes other than income taxes were $52.6 million compared to $47.4 million for the corresponding period in 2013.The increases were primarily due to increases in franchise fees and gross receipts taxes as a result of higher retail revenues. Franchise fees and gross receipts taxes have no impact on net income.

Allowance for Equity Funds Used During Construction

Second Quarter 2014 vs. Second Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$1.2	77.6	$2.4	91.4

In the second quarter 2014, AFUDC equity was $2.7 million compared to $1.5 million for the corresponding period in 2013. For year-to-date 2014, AFUDC equity was$5.1 million compared to $2.7 million for the corresponding period in 2013.These increases wereprimarily due toincreased construction projects related to environmental control projects at generation facilities.

Income Taxes

Second Quarter 2014 vs. Second Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$0.6	3.3	$9.9	28.3

In the second quarter 2014, income taxes were $21.4 million compared to $20.8 million for the corresponding period in 2013. For year-to-date 2014, income taxes were$44.7 million compared to $34.8 million for the corresponding period in 2013.These increases wereprimarily due to higher pre-tax earnings, partially offset by an increase in non-taxable AFUDC equity.

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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 is 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 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 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 57% through 2018. The second type, referred to as requirements service, provides that Gulf Power serves the customer's capacity and energy requirements from other Gulf Power resources.

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. 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 DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" and "PSC 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

Air Quality

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Air Quality" of Gulf Power in Item 7 of the Form 10-K for additional information regarding the Cross State Air Pollution Rule (CSAPR) and the EPA's proposed rules regarding the regulation of excess emissions during periods of startup, shutdown, or malfunction (SSM).

On April 29, 2014, the U.S. Supreme Court overturned the U.S. Court of Appeals for the District of Columbia Circuit's August 2012 decision to vacate CSAPR and remanded the case back to the U.S. Court of Appeals for the District of Columbia Circuit for further proceedings. On June 26, 2014, the EPA requested that the U.S. Court of

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Appeals for the District of Columbia Circuit lift the stay on CSAPR and approve a revised schedule with compliance to begin on January 1, 2015.

On June 10, 2014, the EPA entered into a revised settlement agreement requiring it to issue a supplemental proposed SSM rule by September 5, 2014 and finalize the proposed rule by May 22, 2015.

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

Water Quality

On April 21, 2014, the EPA and the U.S. Army Corps of Engineers jointly published a proposed rule to revise the regulatory definition of waters of the U.S. for all Clean Water Act (CWA) programs, significantly expanding the scope of federal jurisdiction under the CWA. If finalized as proposed, this rule could significantly increase permitting and regulatory requirements and costs associated with the siting of new facilities and the installation, expansion, and maintenance of transmission and distribution lines. In addition, the rule as proposed could have significant impacts on economic development projects which could affect customer demand growth. The ultimate impact of the proposed rule will depend on the specific requirements of the final rule and the outcome of any legal challenges and cannot be determined at this time.

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Water Quality" of Gulf Power in Item 7 of the Form 10-K for additional information regarding the EPA's rulemaking for cooling water intake structures.

On May 19, 2014, the EPA signed a final rule establishing standards for reducing effects on fish and other aquatic life caused by new and existing cooling water intake structures at existing power plants and manufacturing facilities. The ultimate outcome of this final rule will depend on the results of additional studies and implementation of the rule by state regulators, but could result in additional capital and operational costs associated with changes to existing intake structures and cooling systems and increased costs associated with the construction of new generating units. The ultimate impact of this rule will depend on the outcome of any legal challenges and cannot be determined at this time.

Global Climate Issues

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues" of Gulf Power in Item 7 of the Form 10-K for additional information regarding the EPA's current and proposed regulation of GHG emissions under the Clean Air Act.

On June 18, 2014, the EPA published the proposed Clean Power Plan, setting forth guidelines for states to develop plans to address CO₂ emissions from existing fossil fuel-fired electric generating units. The EPA's proposed guidelines establish state-specific interim and final CO₂ emission rate goals to be achieved between 2020 and 2029 and in 2030 and thereafter. The EPA also published the proposed CO₂ performance standards for modified and reconstructed fossil fuel-fired electric generating units. If finalized as proposed, the proposed guidelines and standards could result in operational restrictions and material compliance costs, including capital expenditures, that could impact unit retirement and replacement decisions. Also, additional compliance costs could affect results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates. Further, any resulting higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively impact results of operations, cash flows, and financial condition. The ultimate impact of these proposals will depend on the specific requirements of the final guidelines and performance standards, implementation by states, and the outcome of any legal challenges and cannot be determined at this time.

On June 23, 2014, the U.S. Supreme Court struck down a portion of the EPA's program for GHG permitting under the Prevention of Significant Deterioration and Title V operating permit programs, holding that a facility's GHG emissions alone could not trigger a requirement to obtain a permit and that the EPA did not have the authority to tailor the statutory permitting thresholds. The ultimate impact of this decision cannot be determined at this time.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

PSC Matters

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 $5.4 million reduction in depreciation expense in the first six months of 2014.

Cost Recovery Clauses

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC 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. The recovery balance of each regulatory clause for Gulf Power is reported in Note (B) to the Condensed Financial Statements herein.

Retail Fuel Cost Recovery

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Fuel Cost Recovery" of Gulf Power in Item 7 and Note 1 and Note 3 to the financial statements of Gulf Power under "Revenues" and "Retail Regulatory Matters – Fuel Cost Recovery," respectively, in Item 8 of the Form 10-K for additional information.

Gulf Power has established fuel cost recovery rates as approved annually by the Florida PSC. In late 2013 and the first six months of 2014, Gulf Power experienced higher than expected costs for natural gas and purchased power along with lower fuel revenues for non-territorial sales. If the projected year-end fuel cost over or under recovery balance exceeds 10% of the projected fuel revenues for the period, Gulf Power is required to notify the Florida PSC and indicate if an adjustment to the fuel recovery factor is being requested. Gulf Power filed such notice with the Florida PSC on July 18, 2014, but no adjustment to the factor was requested. Under recovered fuel costs at June 30, 2014 totaled $43.4 million and are included in under recovered regulatory clause revenues on Gulf Power's Condensed Balance Sheet herein. Fuel cost recovery revenues, as recorded on the financial statements, are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, any changes in the billing factor would have no significant effect on Gulf Power's revenues or net income, but will affect cash flow.

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 increased generally throughout the U.S. In particular, personal injury, property damage, and other claims for damages alleged to have been caused by CO₂ and other emissions, coal combustion residuals, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters, have become more frequent.

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

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GULF POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Power's financial statements. See the Notes 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 and Pension and Other Postretirement Benefits.

Recently Issued Accounting Standards

On May 28, 2014, the Financial Accounting Standards Board issued ASC 606, Revenue from Contracts with Customers. ASC 606 revises the accounting for revenue recognition and is effective for fiscal years beginning after December 15, 2016. Gulf Power is currently evaluating the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined.

FINANCIAL CONDITION AND LIQUIDITY

Overview

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Gulf Power in Item 7 of the Form 10-K for additional information. Gulf Power's financial condition remained stable at June 30, 2014. Gulf Power intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.

Net cash provided from operating activities totaled $177.2 million for the first six months of 2014 compared to $113.4 million for the corresponding period in 2013. The $63.8 million increase in net cash was primarily due to changes in cash flows related to cost recovery clauses and a decrease in fossil fuel stock resulting from an increase in KWH generation. Net cash used for investing activities totaled $170.5 million in the first six months of 2014 primarily due to property additions to utility plant. Net cash provided from financing activities totaled $1.3 million for the first six months of 2014 primarily due to the issuance of common stock to Southern Company and the issuance of long-term debt, partially offset by the payment of common stock dividends and the redemption 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 six months of 2014 include a net increase of $101.2 million in property, plant, and equipment primarily for construction of generation, transmission, and distribution facilities and an increase of $50.0 million in common stock due to the issuance of common stock to Southern Company. Decreases included $39.2 million in fossil fuel stock resulting from an increase in KWH generation.

Capital Requirements and Contractual Obligations

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Gulf Power in Item 7 of the Form 10-K for a description of Gulf Power's capital requirements for its construction program, including estimated capital expenditures to comply with existing environmental statutes and regulations, scheduled maturities of long-term debt, as well as related

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

interest, leases, derivative obligations, preference stock dividends, purchase commitments, trust funding requirements, and unrecognized tax benefits. Approximately $75 million will be required through June 30, 2015 to fund maturities of long-term debt.

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

Sources of Capital

Gulf Power plans to obtain the funds required for construction and other purposes from sources similar to those used in the past, which were primarily from operating cash flows, short-term debt, 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 to meet liquidity needs.

At June 30, 2014, Gulf Power had approximately $29.7 million of cash and cash equivalents. Committed credit arrangements with banks at June 30, 2014 were as follows:

Expires(a)												Executable Term Loans				Due Within One Year
2014		2015		2016		2017		Total		Unused		One Year		Two Years		Term Out		No Term Out
(in millions)								(in millions)				(in millions)				(in millions)
$	20	$	60	$	165	$	30	$	275	$	275	$	50	$	—	$	50	$	30

(a) No credit arrangements expire in 2018.

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 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 arrangements contain material adverse change clauses at the time of borrowings. In May and June 2014, Gulf Power renewed credit arrangements for $30 million and $25 million, respectively. The $30 million credit arrangement will expire in May 2017 and the $25 million credit arrangement will expire in June 2015. Gulf Power expects to renew its credit arrangements, as needed, prior to expiration.

A portion of the unused credit arrangements with banks provide liquidity support to Gulf 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 June 30, 2014 was approximately $69 million. In

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

addition, at June 30, 2014, Gulf Power had $65 million of fixed rate pollution control revenue bonds that are 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.

Details of short-term borrowings were as follows:

	Short-term Debt at June 30, 2014			Short-term Debt During the Period(a)
	Amount Outstanding		Weighted Average Interest Rate	Average Outstanding		Weighted Average Interest Rate	Maximum Amount Outstanding
	(in millions)			(in millions)			(in millions)
Commercial paper	$	139	0.2%	$	96	0.2%	$	145

(a) Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 2014.

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

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 June 30, 2014 were as follows:

Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB- and/or Baa3	$	74
Below BBB- and/or Baa3	392

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 second quarter 2014 has not changed materially compared to the December 31, 2013 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 57% through 2018. 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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GULF POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Financing Activities

In January 2014, Gulf Power issued 500,000 shares of common stock to Southern Company and realized proceeds of $50 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 April 2014, Gulf Power executed a loan agreement with Mississippi Business Finance Corporation (MBFC) related to MBFC's issuance of $29.075 million aggregate principal amount of Pollution Control Revenue Refunding Bonds, First Series 2014 (Gulf Power Company Project) due April 1, 2044 for the benefit of Gulf Power. The proceeds were used to redeem $29.075 million aggregate principal amount of MBFC Pollution Control Revenue Refunding Bonds, Series 2003 (Gulf Power Company Project).

In June 2014, Gulf Power reoffered to the public $13 million aggregate principal amount of MBFC Solid Waste Disposal Facilities Revenue Refunding Bonds, Series 2012 (Gulf Power Company Project), which had been previously purchased and held by Gulf Power since December 2013.

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

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MISSISSIPPI POWER COMPANY

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MISSISSIPPI POWER COMPANY

CONDENSED STATEMENTS OF OPERATIONS (UNAUDITED)

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2014			2013			2014			2013
	(in thousands)						(in thousands)
Operating Revenues:
Retail revenues	$	211,326		$	214,254		$	418,364		$	382,564
Wholesale revenues, non-affiliates	74,972			71,938			171,690			137,047
Wholesale revenues, affiliates	20,165			15,902			42,954			24,243
Other revenues	4,512			4,341			9,128			8,515
Total operating revenues	310,975			306,435			642,136			552,369
Operating Expenses:
Fuel	143,317			142,193			290,268			246,757
Purchased power, non-affiliates	1,194			1,778			12,688			3,145
Purchased power, affiliates	5,735			3,922			14,664			13,611
Other operations and maintenance	60,070			54,456			126,165			109,268
Depreciation and amortization	24,242			22,209			46,936			45,442
Taxes other than income taxes	20,396			20,272			40,854			39,689
Estimated loss on Kemper IGCC	—			450,000			380,000			912,000
Total operating expenses	254,954			694,830			911,575			1,369,912
Operating Income (Loss)	56,021			(388,395		)	(269,439		)	(817,543		)
Other Income and (Expense):
Allowance for equity funds used during construction	37,380			29,042			75,462			55,116
Interest expense, net of amounts capitalized	(12,620		)	(10,389		)	(24,655		)	(20,798		)
Other income (expense), net	(1,933		)	(2,262		)	(3,732		)	(3,809		)
Total other income and (expense)	22,827			16,391			47,075			30,509
Earnings (Loss) Before Income Taxes	78,848			(372,004		)	(222,364		)	(787,034		)
Income taxes (benefit)	15,920			(153,327		)	(113,677		)	(322,469		)
Net Income (Loss)	62,928			(218,677		)	(108,687		)	(464,565		)
Dividends on Preferred Stock	433			433			866			866
Net Income (Loss) After Dividends on Preferred Stock	$	62,495		$	(219,110	)	$	(109,553	)	$	(465,431	)

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (UNAUDITED)

	For the Three Months Ended June 30,					For the Six Months Ended June 30,
	2014		2013			2014			2013
	(in thousands)					(in thousands)
Net Income (Loss)	$	62,928	$	(218,677	)	$	(108,687	)	$	(464,565	)
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $1, $-, $- and $-, respectively	1		—			—			—
Reclassification adjustment for amounts included in net income, net of tax of $132, $132, $263 and $263, respectively	212		213			425			425
Total other comprehensive income (loss)	213		213			425			425
Comprehensive Income (Loss)	$	63,141	$	(218,464	)	$	(108,262	)	$	(464,140	)

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 STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Six Months Ended June 30,
	2014			2013
	(in thousands)
Operating Activities:
Net income (loss)	$	(108,687	)	$	(464,565	)
Adjustments to reconcile net income (loss)   to net cash provided from (used for) operating activities —
Depreciation and amortization, total	49,869			43,263
Deferred income taxes	(107,556		)	(337,167		)
Investment tax credits received	27,750			66,474
Allowance for equity funds used during construction	(75,462		)	(55,116		)
Pension, postretirement, and other employee benefits	2,551			6,184
Stock based compensation expense	1,878			1,547
Regulatory assets associated with Kemper IGCC	(26,091		)	(13,399		)
Estimated loss on Kemper IGCC	380,000			912,000
Kemper regulatory deferral	67,125			26,979
Other, net	2,266			1,068
Changes in certain current assets and liabilities —
-Receivables	(11,972		)	(37,431		)
-Under recovered regulatory clause revenues	(19,842		)	—
-Fossil fuel stock	31,707			34,205
-Materials and supplies	(5,607		)	(6,509		)
-Prepaid income taxes	(12,261		)	8,823
-Other current assets	1,063			(4,879		)
-Accounts payable	4,424			(5,417		)
-Accrued taxes	(22,513		)	(24,101		)
-Accrued interest	13,256			8,502
-Accrued compensation	3,634			(10,461		)
-Over recovered regulatory clause revenues	(18,358		)	(27,838		)
-Other current liabilities	1,031			282
Net cash provided from operating activities	178,205			122,444
Investing Activities:
Property additions	(691,859		)	(789,021		)
Cost of removal, net of salvage	(5,358		)	(2,033		)
Construction payables	(28,326		)	23,314
Capital grant proceeds	—			4,500
Other investing activities	(7,920		)	(11,172		)
Net cash used for investing activities	(733,463		)	(774,412		)
Financing Activities:
Proceeds —
Capital contributions from parent company	211,027			351,198
Bonds-Other	12,318			15,814
Interest-bearing refundable deposit related to asset sale	75,000			—
Long-term debt issuance to parent company	220,000			—
Other long-term debt issuances	250,000			350,000
Redemptions — Capital leases	(1,254		)	—
Payment of preferred stock dividends	(866		)	(866		)
Payment of common stock dividends	—			(71,956		)
Return of capital	(109,860		)	(16,424		)
Other financing activities	(381		)	(1,431		)
Net cash provided from financing activities	655,984			626,335
Net Change in Cash and Cash Equivalents	100,726			(25,633		)
Cash and Cash Equivalents at Beginning of Period	145,165			145,008
Cash and Cash Equivalents at End of Period	$	245,891		$	119,375
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (paid $37,436 and $37,036, net of $29,087 and $23,613 capitalized for 2014 and 2013, respectively)	$	8,349		$	13,423
Income taxes, net	(33,621		)	(64,062		)
Noncash transactions — accrued property additions at end of period	135,675			238,177

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

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MISSISSIPPI POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Assets	At June 30, 2014			At December 31, 2013
	(in thousands)
Current Assets:
Cash and cash equivalents	$	245,891		$	145,165
Receivables —
Customer accounts receivable	43,988			40,978
Unbilled revenues	43,271			38,895
Under recovered regulatory clause revenues	19,842			—
Other accounts and notes receivable	2,646			4,600
Affiliated companies	41,460			34,920
Accumulated provision for uncollectible accounts	(1,193		)	(3,018		)
Fossil fuel stock, at average cost	81,578			113,285
Materials and supplies, at average cost	50,954			45,347
Other regulatory assets, current	54,629			52,496
Prepaid income taxes	14,989			34,751
Other current assets	9,492			9,357
Total current assets	607,547			516,776
Property, Plant, and Equipment:
In service	3,492,473			3,458,770
Less accumulated provision for depreciation	1,128,231			1,095,352
Plant in service, net of depreciation	2,364,242			2,363,418
Construction work in progress	2,925,736			2,586,031
Total property, plant, and equipment	5,289,978			4,949,449
Other Property and Investments	5,026			4,857
Deferred Charges and Other Assets:
Deferred charges related to income taxes	177,865			139,834
Other regulatory assets, deferred	220,994			200,620
Accumulated deferred income taxes	16,025			—
Other deferred charges and assets	47,548			36,673
Total deferred charges and other assets	462,432			377,127
Total Assets	$	6,364,983		$	5,848,209

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

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MISSISSIPPI POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholder's Equity	At June 30, 2014			At December 31, 2013
	(in thousands)
Current Liabilities:
Securities due within one year	$	426,170		$	13,789
Interest-bearing refundable deposit related to asset sale	225,000			150,000
Accounts payable —
Affiliated	80,445			70,299
Other	176,142			210,191
Customer deposits	14,980			14,379
Accrued taxes —
Accrued income taxes	16,732			5,590
Other accrued taxes	45,135			77,958
Accrued interest	60,386			47,144
Accrued compensation	12,958			9,324
Other regulatory liabilities, current	19,937			24,981
Over recovered regulatory clause liabilities	—			18,358
Other current liabilities	19,612			21,413
Total current liabilities	1,097,497			663,426
Long-term Debt:
Long-term debt, affiliated	220,000			—
Long-term debt, non-affiliated	2,011,293			2,167,067
Total Long-term Debt	2,231,293			2,167,067
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	19,157			72,808
Deferred credits related to income taxes	7,553			9,145
Accumulated deferred investment tax credits	283,671			284,248
Employee benefit obligations	94,164			94,430
Asset retirement obligations	42,169			41,197
Other cost of removal obligations	160,277			151,340
Other regulatory liabilities, deferred	213,827			140,880
Other deferred credits and liabilities	12,203			14,337
Total deferred credits and other liabilities	833,021			808,385
Total Liabilities	4,161,811			3,638,878
Redeemable Preferred Stock	32,780			32,780
Common Stockholder's Equity:
Common stock, without par value —
Authorized —1,130,000 shares
Outstanding—1,121,000 shares	37,691			37,691
Paid-in capital	2,479,564			2,376,595
Retained earnings (deficit)	(339,424		)	(229,871		)
Accumulated other comprehensive loss	(7,439		)	(7,864		)
Total common stockholder's equity	2,170,392			2,176,551
Total Liabilities and Stockholder's Equity	$	6,364,983		$	5,848,209

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

SECOND QUARTER 2014 vs. SECOND QUARTER 2013

AND

YEAR-TO-DATE 2014 vs. YEAR-TO-DATE 2013

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 a constructive regulatory environment, to maintain and grow energy sales given economic conditions, and to effectively manage and secure timely recovery of prudently-incurred costs. These costs include those related to projected long-term demand growth, increasingly stringent environmental standards, reliability, fuel, capital expenditures, restoration following major storms, and the completion and operation of ongoing construction projects, primarily the Kemper IGCC. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Mississippi Power for the foreseeable future.

During 2014, Mississippi Power further revised its cost estimate for the Kemper IGCC to approximately $4.44 billion, net of $245.3 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). The revised cost estimate primarily reflects costs related to decreases in construction labor productivity at the Kemper IGCC due in large part to adverse weather, unexpected excessive craft labor turn-over, and unanticipated installation inefficiencies, as well as additional risk related to the expected in-service date as described herein.

Mississippi Power does not intend to seek any rate recovery or joint owner contributions for any costs related to the construction and start-up 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 revised cost estimate, Mississippi Power recorded total pre-tax charges to income for the estimated probable losses on the Kemper IGCC of $380.0 million ($234.7 million after tax) in the first quarter 2014.

Mississippi Power currently expects to place the combined cycle and the associated common facilities portion of the Kemper IGCC project in service in the summer of 2014 and continues to focus on completing the remainder of the Kemper IGCC, including the gasification system. The in-service date for the remainder of the Kemper IGCC is currently expected to occur in the second quarter 2015. The revised cost estimate above includes costs through May 31, 2015. As a result of the additional factors that have the potential to impact start-up 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.

Mississippi Power continues to focus on several key performance indicators, including the construction 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

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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" herein for information regarding the revision to the cost estimate for the Kemper IGCC that has negatively impacted Mississippi Power's actual performance on net income after dividends on preferred stock, one of its key performance indicators, for 2014, as compared to the target.

RESULTS OF OPERATIONS

Net Income (Loss)

Second Quarter 2014 vs. Second Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$281.6	128.5	$355.8	76.5

Mississippi Power's net income after dividends on preferred stock for the second quarter 2014 was $62.5 million compared to a net loss after dividends on preferred stock of $219.1 million for the corresponding period in 2013. The change was primarily related to a $450.0 million pre-tax charge ($277.9 million after tax) in the second quarter 2013 for a revision 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 loss was partially offset by an increase in AFUDC equity primarily related to the construction of the Kemper IGCC and an increase in revenues primarily due to retail and wholesale base rate increases and the recognition as revenue of a portion of the retail rate increase related to the Kemper IGCC cost recovery that became effective on March 19, 2013.

For year-to-date 2014, the net loss after dividends on preferred stock was $109.6 million compared to $465.4 million for the corresponding period in 2013. The change was primarily related to a $380.0 million pre-tax charge ($234.7 million after tax) in the first quarter 2014 compared to $912.0 million in pre-tax charges ($563.2 million after tax) in the first half of 2013 for revisions of 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 loss was partially offset by an increase in AFUDC equity primarily related to the construction of the Kemper IGCC and an increase in revenues primarily due to retail and wholesale base rate increases and the recognition as revenue of a portion of the retail rate increase related to the Kemper IGCC cost recovery that became effective on March 19, 2013.

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

Second Quarter 2014 vs. Second Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$(3.0)	(1.4)	$35.8	9.4

In the second quarter 2014, retail revenues were $211.3 million compared to $214.3 million for the corresponding period in 2013. For year-to-date 2014, retail revenues were $418.4 million compared to $382.6 million for the corresponding period in 2013.

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Details of the changes in retail revenues were as follows:

	Second Quarter 2014					Year-to-Date  2014
	(in millions)			(% change)		(in millions)		(% change)
Retail – prior year	$	214.3				$	382.6
Estimated change resulting from –
Rates and pricing	—			—		11.9		3.1
Sales growth	0.4			0.2		1.4		0.4
Weather	(0.9		)	(0.4	)	1.5		0.4
Fuel and other cost recovery	(2.5		)	(1.2	)	21.0		5.5
Retail – current year	$	211.3		(1.4	)%	$	418.4	9.4	%

Revenues associated with changes in rates and pricing did not change in the second quarter 2014 and increased year-to-date 2014 when compared to the corresponding periods in 2013. The increase for year-to-date 2014 was due to a PEP base rate increase and the recognition as revenue of a portion of the rate increase related to Kemper IGCC cost recovery, both of which were effective on March 19, 2013, and a $4.7 million refund in 2013 related to the annual PEP lookback filing.

See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" and "Retail Regulatory Matters – Performance Evaluation Plan" 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.

Revenues attributable to changes in sales increased slightly in the second quarter 2014 when compared to the corresponding period in 2013. KWH energy sales to industrial customers increased 4.1% when compared to the corresponding period in 2013 due to increased usage by larger customers. Weather-adjusted KWH energy sales to residential customers decreased 2.5% when compared to the corresponding period in 2013 due to lower average usage per customer. Weather-adjusted KWH energy sales to commercial customers decreased 1.9% when compared to the corresponding period in 2013 due to decreased commercial economic activity.

Revenues attributable to changes in sales increased for year-to-date 2014 when compared to the corresponding period in 2013. KWH energy sales to industrial customers increased 3.6% when compared to the corresponding period in 2013 due to increased usage by larger customers. Weather-adjusted KWH energy sales to residential customers decreased 0.7% when compared to the corresponding period in 2013 due to lower average usage per customer. Weather-adjusted KWH energy sales to commercial customers increased 0.3% when compared to the corresponding period in 2013 due to an increase in the number of commercial customers.

Fuel and other cost recovery revenues decreased in the second quarter 2014 when compared to the corresponding period in 2013 primarily as a result of lower recoverable fuel costs. Fuel and other cost recovery revenues increased year-to-date 2014 when compared to the corresponding period in 2013 primarily as a result of higher recoverable fuel costs. See "Fuel and Purchased Power Expenses" herein for additional information. Recoverable fuel costs include fuel and purchased power expenses reduced by the fuel portion of wholesale revenues from energy sold to customers outside Mississippi Power's service territory. Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the energy component of purchased power costs, and do not affect net income.

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Wholesale Revenues – Non-Affiliates

Second Quarter 2014 vs. Second Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$3.1	4.2	$34.7	25.3

Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Mississippi Power's and the Southern Company system's generation, demand for energy within the Southern Company system's 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 rural electric cooperative associations and municipalities located in southeastern Mississippi under long-term contracts with 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 second quarter 2014, wholesale revenues from sales to non-affiliates were $75.0 million compared to $71.9 million for the corresponding period in 2013. The increase was due to a $1.2 million increase in base revenues primarily resulting from a wholesale base rate increase effective beginning May 1, 2014 and a $1.9 million increase in energy revenues primarily resulting from an increase in KWH sales associated with short-term opportunity sales in the second quarter 2014 compared to the corresponding period in 2013. Short-term opportunity sales are made at market-based rates that generally provide a margin above Mississippi Power's variable cost of energy.

For year-to-date 2014, wholesale revenues from sales to non-affiliates were $171.7 million compared to $137.0 million for the corresponding period in 2013. The increase was due to a $15.2 million increase in base revenues primarily resulting from wholesale base rate increases effective April 1, 2013 and May 1, 2014 and a $19.4 million increase in energy revenues, of which $8.8 million was primarily associated with higher fuel prices and $10.6 million was associated with an increase in KWH sales primarily due to the higher demand resulting from colder weather in the first quarter 2014 compared to the corresponding period in 2013.

Wholesale Revenues – Affiliates

Second Quarter 2014 vs. Second Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$4.3	26.8	$18.8	77.2

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 the energy is generally sold at marginal cost.

In the second quarter 2014, wholesale revenues from sales to affiliates were $20.2 million compared to $15.9 million for the corresponding period in 2013. The increase was due to a $4.3 million increase in energy revenues, $5.3 million of which was associated with an increase in KWH sales, partially offset by a $1.0 million decrease associated with lower prices.

For year-to-date 2014, wholesale revenues from sales to affiliates were $43.0 million compared to $24.2 million for the corresponding period in 2013. The increase was due to an $18.8 million increase in energy revenues, $15.7 million of which was associated with an increase in KWH sales and $3.1 million was associated with higher prices.

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Fuel and Purchased Power Expenses

	Second Quarter 2014 vs. Second Quarter 2013				Year-to-Date 2014 vs. Year-to-Date 2013
	(change in millions)			(% change)	(change in millions)		(% change)
Fuel	$	1.1		0.8	$	43.5	17.6
Purchased power – non-affiliates	(0.6		)	(32.8)	9.5		N/M
Purchased power – affiliates	1.8			46.2	1.1		7.7
Total fuel and purchased power expenses	$	2.3			$	54.1

N/M - Not meaningful

In the second quarter 2014, total fuel and purchased power expenses were $150.2 million compared to $147.9 million for the corresponding period in 2013. The increase was due to a $9.9 million increase in the total volume of KWHs generated, partially offset by a $7.6 million decrease in the cost of fuel.

For year-to-date 2014, total fuel and purchased power expenses were $317.6 million compared to $263.5 million for the corresponding period in 2013. The increase was due to a $50.5 million increase in the total volume of KWHs generated and a $3.6 million increase in the cost of fuel and purchased power.

Fuel and purchased power energy transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through Mississippi Power's fuel cost recovery clause. See FUTURE EARNINGS POTENTIAL – "PSC Matters – Fuel Cost Recovery" herein for additional information.

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

	Second Quarter 2014	Second Quarter 2013	Year-to-Date 2014	Year-to-Date 2013
Total generation (millions of KWHs)(a)	3,932	3,753	7,974	6,957
Total purchased power (millions of KWHs)	208	209	466	601
Sources of generation (percent)(a) –
Coal	47	43	46	35
Gas	53	57	54	65
Cost of fuel, generated (cents per net KWH) –
Coal	4.18	4.90	4.21	4.94
Gas(a)	3.62	3.39	3.61	3.17
Average cost of fuel, generated (cents per net KWH)(a)	3.90	4.09	3.91	3.85
Average cost of purchased power (cents per net KWH)(a)	3.33	2.73	5.87	2.79

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

Fuel

In the second quarter 2014, fuel expense was $143.3 million compared to $142.2 million for the corresponding period in 2013. The increase was primarily due to a 5.5% increase in the volume of KWHs generated to meet demand in the second quarter 2014 as compared to the corresponding period in 2013, partially offset by a 4.7% decrease in the average cost of fuel per KWH generated primarily due to higher coal-fired generation at lower coal prices, partially offset by higher natural gas prices.

For year-to-date 2014, fuel expense was $290.3 million compared to $246.8 million for the corresponding period in 2013. The increase was primarily due to a 16.0% increase in the volume of KWHs generated to meet demand related to colder weather in the first quarter 2014 as compared to the corresponding period in 2013 and a 1.6%

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increase in the average cost of fuel per KWH generated, primarily due to higher natural gas prices and higher coal-fired generation.

Purchased Power - Non-Affiliates

In the second quarter 2014, purchased power expense from non-affiliates was $1.2 million compared to $1.8 million for the corresponding period in 2013. The decrease was primarily the result of a 45.6% decrease in the volume of KWHs purchased, partially offset by a 23.5% increase in the average cost per KWH purchased.

For year-to-date 2014, purchased power expense from non-affiliates was $12.7 million compared to $3.2 million for the corresponding period in 2013. The increase was primarily due to a 360.8% increase in the average cost per KWH purchased, partially offset by a 12.4% decrease in the volume of KWHs purchased.

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 second quarter 2014, purchased power expense from affiliates was $5.7 million compared to $3.9 million for the corresponding period in 2013. The increase was primarily due to a 33.8% increase in the volume of KWHs purchased and a 9.3% increase in the average cost per KWH purchased.

For year-to-date 2014, purchased power expense from affiliates was $14.7 million compared to $13.6 million for the corresponding period in 2013. The increase was primarily due to a 46.1% increase in the average cost per KWH purchased, partially offset by a 26.3% decrease in the volume of KWHs purchased.

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.

Other Operations and Maintenance Expenses

Second Quarter 2014 vs. Second Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$5.6	10.3	$16.9	15.5

In the second quarter 2014, other operations and maintenance expenses were $60.1 million compared to $54.5 million for the corresponding period in 2013. The increase was primarily due to a $5.0 million increase in labor expenses and a $0.9 million increase in administrative and general expenses.

For year-to-date 2014, other operations and maintenance expenses were $126.2 million compared to $109.3 million for the corresponding period in 2013. The increase was primarily due to an $11.2 million increase in generation maintenance expenses primarily related to scheduled outages and a $7.8 million increase in labor expenses. These increases were partially offset by a $2.1 million decrease in customer accounting, services, and sales expenses primarily due to uncollectible expenses.

Depreciation and Amortization

Second Quarter 2014 vs. Second Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$2.0	9.2	$1.5	3.3

In the second quarter 2014, depreciation and amortization was $24.2 million compared to $22.2 million for the corresponding period in 2013. For year-to-date 2014, depreciation and amortization was $46.9 million compared to

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$45.4 million for the corresponding period in 2013. These increases were primarily due to the increase in amortization resulting from a regulatory deferral associated with the purchase of Plant Daniel Units 3 and 4.

See Note 1 to the financial statements of Mississippi Power under "Purchase of the Plant Daniel Combined Cycle Generating Units" and "Depreciation and Amortization" in Item 8 of the Form 10-K for additional information.

Estimated Loss on Kemper IGCC

Second Quarter 2014 vs. Second Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$(450.0)	(100.0)	$(532.0)	(58.3)

In the second quarter 2013, an estimated probable loss on the Kemper IGCC of $450.0 million was recorded at Mississippi Power. For year-to-date 2014 and year-to-date 2013, estimated probable losses on the Kemper IGCC of $380.0 million and $912.0 million, respectively, were recorded at Mississippi Power. These losses reflect revisions of estimated costs expected to be incurred on the construction of the Kemper IGCC in excess of the $2.88 billion cost cap established by the Mississippi PSC, net of the DOE Grants and excluding the Cost Cap Exceptions.

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

Allowance for Equity Funds Used During Construction

Second Quarter 2014 vs. Second Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$8.4	28.7	$20.4	36.9

In the second quarter 2014, AFUDC equity was $37.4 million compared to $29.0 million for the corresponding period in 2013. For year-to-date 2014, AFUDC equity was $75.5 million compared to $55.1 million for the corresponding period in 2013. These increases were primarily due to the construction of the Kemper IGCC. See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information regarding the Kemper IGCC.

Interest Expense, Net of Amounts Capitalized

Second Quarter 2014 vs. Second Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$2.2	21.5	$3.9	18.5

In the second quarter 2014, interest expense, net of amounts capitalized was $12.6 million compared to $10.4 million for the corresponding period in 2013. The increase was primarily due to a $2.5 million increase in interest expense resulting from the receipt of a $75.0 million interest-bearing refundable deposit from SMEPA in January 2014 related to its pending purchase of an undivided interest in the Kemper IGCC, a $1.7 million increase in interest expense on the regulatory liability related to the Kemper IGCC rate recovery, and a $1.0 million increase in interest expense associated with issuances of new long-term debt. These increases were partially offset by a $1.7 million increase in capitalized interest primarily resulting from AFUDC debt and carrying costs related to the Kemper IGCC and a $1.0 million decrease in interest expense associated with the redemption of long-term debt in 2013.

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For year-to-date 2014, interest expense, net of amounts capitalized was $24.7 million compared to $20.8 million for the corresponding period in 2013. The increase was primarily due to a $4.8 million increase in interest expense resulting from the receipt of a $75.0 million interest-bearing refundable deposit from SMEPA in January 2014 related to its pending purchase of an undivided interest in the Kemper IGCC, a $3.0 million increase in interest expense on the regulatory liability related to the Kemper IGCC rate recovery, and a $2.2 million increase in interest expense associated with issuances of new long-term debt. These increases were partially offset by a $3.5 million increase in capitalized interest primarily resulting from AFUDC debt and carrying costs related to the Kemper IGCC and a $1.9 million decrease in interest expense associated with the redemption of long-term debt in 2013.

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.

Income Taxes (Benefit)

Second Quarter 2014 vs. Second Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$169.2	110.4	$208.8	64.7

In the second quarter 2014, income taxes (benefit) were $15.9 million compared to $(153.3) million for the corresponding period in 2013. For year-to-date 2014, income taxes (benefit) were $(113.7) million compared to $(322.5) million for the corresponding period in 2013. These changes were primarily due to lower pre-tax losses related to the estimated probable losses recorded on the construction of the Kemper IGCC.

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 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 the Kemper IGCC and the Plant Daniel scrubber project. Future earnings in the near term will depend, in part, upon maintaining and growing sales which is subject to a number of factors. These factors include weather, competition, new energy contracts with other utilities, energy conservation practiced 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. 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 Mississippi Power in Item

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

Environmental Statutes and Regulations

Air Quality

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Air Quality" of Mississippi Power in Item 7 of the Form 10-K for additional information regarding the Cross State Air Pollution Rule (CSAPR), the EPA's proposed rules regarding the regulation of excess emissions during periods of startup, shutdown, or malfunction (SSM), and the Mercury and Air Toxics Standards rule.

On April 29, 2014, the U.S. Supreme Court overturned the U.S. Court of Appeals for the District of Columbia Circuit's August 2012 decision to vacate CSAPR and remanded the case back to the U.S. Court of Appeals for the District of Columbia Circuit for further proceedings. On June 26, 2014, the EPA requested that the U.S. Court of Appeals for the District of Columbia Circuit lift the stay on CSAPR and approve a revised schedule with compliance to begin on January 1, 2015.

On June 10, 2014, the EPA entered into a revised settlement agreement requiring it to issue a supplemental proposed SSM rule by September 5, 2014 and finalize the proposed rule by May 22, 2015.

See "PSC Matters – Environmental Compliance Overview Plan" and "Other Matters – Sierra Club Settlement Agreement" and Note (B) to the Condensed Financial Statements under "PSC Matters – Environmental Compliance Overview Plan" and "Other Matters – Sierra Club Settlement Agreement" herein for additional information regarding generating unit retirement, repowering, and/or conversion.

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

Water Quality

On April 21, 2014, the EPA and the U.S. Army Corps of Engineers jointly published a proposed rule to revise the regulatory definition of waters of the U.S. for all Clean Water Act (CWA) programs, significantly expanding the scope of federal jurisdiction under the CWA. If finalized as proposed, this rule could significantly increase permitting and regulatory requirements and costs associated with the siting of new facilities and the installation, expansion, and maintenance of transmission and distribution lines. In addition, the rule as proposed could have significant impacts on economic development projects which could affect customer demand growth. The ultimate impact of the proposed rule will depend on the specific requirements of the final rule and the outcome of any legal challenges and cannot be determined at this time.

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Water Quality" of Mississippi Power in Item 7 of the Form 10-K for additional information regarding the EPA's rulemaking for cooling water intake structures.

On May 19, 2014, the EPA signed a final rule establishing standards for reducing effects on fish and other aquatic life caused by new and existing cooling water intake structures at existing power plants and manufacturing facilities. The ultimate outcome of this final rule will depend on the results of additional studies and implementation of the rule by state regulators, but could result in additional capital and operational costs associated with changes to existing intake structures and cooling systems and increased costs associated with the construction of new generating units. The ultimate impact of this rule will depend on the outcome of any legal challenges and cannot be determined at this time.

Global Climate Issues

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues" of Mississippi Power in Item 7 of the Form 10-K for additional information regarding the EPA's current and proposed regulation of GHG emissions under the Clean Air Act.

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On June 18, 2014, the EPA published the proposed Clean Power Plan, setting forth guidelines for states to develop plans to address CO₂ emissions from existing fossil fuel-fired electric generating units. The EPA's proposed guidelines establish state-specific interim and final CO₂ emission rate goals to be achieved between 2020 and 2029 and in 2030 and thereafter. The EPA also published the proposed CO₂ performance standards for modified and reconstructed fossil fuel-fired electric generating units. If finalized as proposed, the proposed guidelines and standards could result in operational restrictions and material compliance costs, including capital expenditures, that could impact unit retirement and replacement decisions. Also, additional compliance costs could affect results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates. Further, any resulting higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively impact results of operations, cash flows, and financial condition. The ultimate impact of these proposals will depend on the specific requirements of the final guidelines and performance standards, implementation by states, and the outcome of any legal challenges and cannot be determined at this time.

On June 23, 2014, the U.S. Supreme Court struck down a portion of the EPA's program for GHG permitting under the Prevention of Significant Deterioration and Title V operating permit programs, holding that a facility's GHG emissions alone could not trigger a requirement to obtain a permit and that the EPA did not have the authority to tailor the statutory permitting thresholds. The ultimate impact of this decision cannot be determined at this time.

FERC Matters

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 the authority to defer in a regulatory asset costs related to the retirement or partial retirement of generating units as a result of environmental compliance rules. 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, 2014, Mississippi Power reached a settlement agreement with its wholesale customers and filed a request with the FERC for an increase in the Municipal and Rural Associations (MRA) cost-based electric tariff. The settlement agreement, approved by the FERC on May 20, 2014, provides that base rates under the MRA cost-based electric tariff will increase approximately $10.1 million annually, with revised rates effective for services rendered beginning May 1, 2014. The amount of base rate revenues to be received in 2014 from the agreed upon increase is expected to be approximately $6.9 million.

PSC Matters

Energy Efficiency

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Energy Efficiency" of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Energy Efficiency" in Item 8 of the Form 10-K for additional information.

On June 3, 2014, the Mississippi PSC approved Mississippi Power's 2014 Energy Efficiency Quick Start Plan filing, which includes a portfolio of energy efficiency programs. On June 24, 2014, Mississippi Power submitted the 2014 Energy Efficiency Cost Recovery filing, which proposed an increase of $1.5 million in annual retail revenues to recover costs associated with energy efficiency programs. On July 21, 2014, the Mississippi PSC suspended the filing to allow more time for review.

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

Performance Evaluation Plan

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Performance Evaluation Plan" of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Performance Evaluation Plan" in Item 8 of the Form 10-K for additional information regarding Mississippi Power's base rates.

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On March 18, 2014, Mississippi Power submitted its annual PEP lookback filing for 2013, which indicated no surcharge or refund. On March 31, 2014, the Mississippi PSC suspended the filing to allow more time for review.

On June 3, 2014, the Mississippi PSC issued an order for the purpose of investigating and reviewing the adoption of a uniform formula rate plan for Mississippi Power and other regulated electric utilities in Mississippi.

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

Environmental Compliance Overview Plan

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Environmental Compliance Overview Plan" of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Environmental Compliance Overview Plan" in Item 8 of the Form 10-K for additional information regarding the CPCN to construct a scrubber on Plant Daniel Units 1 and 2.

On August 1, 2014, Mississippi Power entered into a settlement agreement with the Sierra Club (Sierra Club Settlement Agreement) that, among other things, requires the Sierra Club to dismiss or withdraw all pending legal and regulatory challenges to the issuance of the CPCN to construct a scrubber on Plant Daniel Units 1 and 2. In addition, and consistent with Mississippi Power's ongoing evaluation of recent environmental rules and regulations, Mississippi Power agreed to retire, repower with natural gas, or convert to an alternative non-fossil fuel source Plant Sweatt Units 1 and 2 (80 MWs) no later than December 2018. Mississippi Power also agreed that it would cease burning coal and other solid fuel at Plant Watson Units 4 and 5 (750 MWs) and begin operating those units solely on natural gas no later than April 2015, and cease burning coal and other solid fuel at Plant Greene County Units 1 and 2 (200 MWs) and begin operating those units solely on natural gas no later than April 2016. On August 4, 2014, Mississippi Power, the Sierra Club, and the Mississippi PSC filed a joint motion to dismiss the appeal related to the CPCN to construct a scrubber on Plant Daniel Units 1 and 2.

In accordance with a 2011 accounting order from the Mississippi PSC, Mississippi Power has the authority to defer in a regulatory asset for future recovery all plant retirement- or partial retirement-related costs resulting from environmental regulations. Approved regulatory asset costs will be amortized over a period to be determined by the Mississippi PSC. As a result, these decisions are not expected to have a material impact on Mississippi Power's financial statements. See "Other Matters – Sierra Club Settlement Agreement" and Note (B) to the Condensed Financial Statements under "Other Matters – Sierra Club Settlement Agreement" herein for additional information.

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

Fuel Cost Recovery

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Fuel Cost Recovery" of Mississippi Power in Item 7 and 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 and Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Mississippi Power – Fuel Cost Recovery" herein for additional information.

At June 30, 2014, the amount of under recovered retail fuel costs included on Mississippi Power's Condensed Balance Sheet herein was $14.5 million compared to over recovered retail fuel costs of $14.5 million at December 31, 2013.

Ad Valorem Tax Adjustment

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

On May 6, 2014, the Mississippi PSC approved Mississippi Power's annual ad valorem tax adjustment factor filing for 2014, which requested an annual rate increase of 0.38%, or $3.6 million in annual retail revenues, primarily due to an increase in property tax rates.

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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.

Kemper IGCC Project Approval

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, which the Sierra Club appealed to the Chancery Court. Later in 2012, the Chancery Court affirmed the 2012 MPSC CPCN Order. In January 2013, the Sierra Club filed an appeal of the Chancery Court's ruling with the Mississippi Supreme Court.

On August 1, 2014, Mississippi Power entered into the Sierra Club Settlement Agreement that, among other things, requires the Sierra Club to dismiss or withdraw all pending legal and regulatory challenges against the Kemper IGCC, including the appeal to the Mississippi Supreme Court related to the 2012 MPSC CPCN. On August 4, 2014, Mississippi Power and the Sierra Club filed a joint motion to dismiss the appeal related to the 2012 MPSC CPCN. Also on August 4, 2014, Thomas A. Blanton, who is not a party to the CPCN appeal, filed a motion to stay the motion to dismiss. See "Other Matters – Sierra Club Settlement Agreement" and Note (B) to the Condensed Financial Statements under "Other Matters – Sierra Club Settlement Agreement" herein for additional information.

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

Kemper IGCC Schedule and Cost Estimate

The certificated cost estimate of the Kemper IGCC included in the 2012 MPSC CPCN Order was $2.4 billion, net of $245.3 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. Exceptions to the $2.88 billion cost cap include the Cost Cap Exceptions, as contemplated in the 2013 Settlement Agreement (defined below) and the 2012 MPSC CPCN Order. Recovery of the Cost Cap Exception amounts remains subject to review and approval by the Mississippi PSC.

The Kemper IGCC was originally scheduled to be placed in service in May 2014. Mississippi Power currently expects to place the combined cycle and the associated common facilities portion of the Kemper IGCC in service in the summer of 2014 and continues to focus on completing the remainder of the Kemper IGCC, including the gasification system, for which the in-service date is currently expected to occur in the second quarter 2015. On August 5, 2014, the Mississippi PSC ordered Mississippi Power to provide an analysis of the costs and benefits of placing the combined cycle and the associated common facilities portion of the Kemper IGCC in service in the summer of 2014 and to identify any expected or necessary accounting treatment and/or potential adjustments or impacts related to revenue recognition or any regulatory liability accounts.

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Mississippi Power's 2010 project estimate, current cost estimate, and actual costs incurred as of June 30, 2014 for the Kemper IGCC are as follows:

Cost Category	2010 Project Estimate(e)		Current Estimate		Actual Costs at June 30, 2014
	(in billions)
Plant Subject to Cost Cap(a)	$	2.40	$	4.44	$	3.81
Lignite Mine and Equipment	0.21		0.24		0.23
CO2 Pipeline Facilities	0.14		0.11		0.10
AFUDC(b)(c)	0.17		0.55		0.37
General Exceptions	0.05		0.10		0.07
Regulatory Asset(c)(d)	—		0.12		0.09
Total Kemper IGCC(a)(c)	$	2.97	$	5.56	$	4.67

(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.

(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."

(c) Amounts in the Current Estimate reflect costs through May 31, 2015, but do not reflect any adjustments as a result of the expected placement of the combined cycle and the associated common facilities portion of the Kemper IGCC in service in the summer of 2014.

(d) 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."

(e) 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 incurred as of June 30, 2014, $3.01 billion was included in CWIP (which is net of the DOE Grants and estimated probable losses of $1.56 billion), $97.1 million in other regulatory assets, and $3.9 million in other deferred charges and assets in Mississippi Power's Condensed Balance Sheet herein, and $1.1 million was previously expensed.

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 $380.0 million ($234.7 million after tax) in the first quarter 2014. This amount is in addition to charges totaling $1.18 billion ($728.7 million after tax) recognized through December 31, 2013. The first quarter 2014 revised cost estimate primarily reflects costs related to decreases in construction labor productivity at the Kemper IGCC identified in March 2014 due in large part to adverse weather, unexpected excessive craft labor turn-over, and unanticipated installation inefficiencies, as well as additional risk related to the expected in-service date as described herein. The revised cost estimate above includes costs through May 31, 2015. Any further extension of the in-service date is currently estimated to result in additional costs of approximately $20 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 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 performance, operational readiness, unforeseen engineering or design problems, start-up activities for this first-of-a-kind technology (including major equipment failure and system integration), and/or operations. 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 income and these changes could be material.

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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 Seven-Year Rate Plan (described below) and other related proceedings during 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.

In 2012, the Mississippi PSC denied Mississippi Power's proposed rate schedule for recovery of financing costs during construction, pending a final ruling from the Mississippi Supreme Court regarding the Sierra Club's appeal of the Mississippi PSC's issuance of the CPCN for the Kemper IGCC (2012 MPSC CWIP Order). Mississippi Power appealed the Mississippi PSC's decision to the Mississippi Supreme Court and requested interim rates under bond. The Mississippi Supreme Court denied Mississippi Power's request for interim rates under bond.

2013 Settlement Agreement

In January 2013, Mississippi Power entered into a settlement agreement with the Mississippi PSC that, among other things, establishes the process for resolving matters regarding cost recovery related to the Kemper IGCC and dismissed Mississippi Power's appeal of the 2012 MPSC CWIP Order (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 allows Mississippi Power to secure alternate financing for costs that are not otherwise recovered in any Mississippi PSC rate proceedings contemplated by the 2013 Settlement Agreement. 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 February 2013. Mississippi Power intends 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 as approved by the Mississippi PSC. The rate recovery necessary to recover the annual costs of securitization is expected to be filed and become effective following completion of the Mississippi PSC's prudence review of the costs to be securitized.

The 2013 Settlement Agreement provides that Mississippi Power may terminate the 2013 Settlement Agreement if certain conditions are not met, if Mississippi Power is unable to secure alternate financing for any prudently-incurred Kemper IGCC costs not otherwise recovered in any Mississippi PSC rate proceeding contemplated by the 2013 Settlement Agreement, or if the Mississippi PSC fails to comply with the requirements of the 2013 Settlement Agreement. Mississippi Power continues to work with the Mississippi PSC and the Mississippi Public Utilities Staff to implement the requirements of the 2013 Settlement Agreement.

2013 MPSC Rate Order

Consistent with the terms of the 2013 Settlement Agreement, in January 2013, Mississippi Power filed a new request to increase retail rates in 2013 by $172 million annually, based on projected investment for 2013.

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In March 2013, the Mississippi PSC issued the 2013 MPSC Rate Order approving retail rate increases of 15% effective March 19, 2013, and 3% effective January 1, 2014, which collectively are designed to collect $156 million annually beginning in 2014. For year-to-date 2014, $74.3 million has been collected, with $11.1 million recognized in retail revenues in Mississippi Power's Condensed Statements of Income herein and the remainder deferred in other regulatory liabilities to be used to mitigate customer rate impacts after the Kemper IGCC is placed in service and included in Mississippi Power's Condensed Balance Sheet herein. Since March 2013, $172.4 million has been collected, with $21.3 million recognized in retail revenues in Mississippi Power's Condensed Statements of Income herein, and the remainder deferred in other regulatory liabilities to be used to mitigate customer rate impacts after the Kemper IGCC is placed in service and included in Mississippi Power's Condensed Balance Sheet herein.

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 during the construction period. 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 to comply with the 2013 MPSC Rate Order by collecting and deferring the approved rates during the construction period unless directed to do otherwise by the Mississippi PSC.

In March 2013, a legal challenge to the 2013 MPSC Rate Order was filed by Thomas A. Blanton with the Mississippi Supreme Court, which remains pending against Mississippi Power and the Mississippi PSC. On April 22, 2014, the Mississippi Supreme Court requested further briefing in this proceeding on a number of substantive issues relating to the 2013 MPSC Rate Order.

Seven-Year Rate Plan

In March 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 (Seven-Year Rate Plan), which is still under review by the Mississippi PSC. In the Seven-Year Rate 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, is integral to the Seven-Year Rate 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 Seven-Year Rate 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 will review the amount and, if approved, determine the appropriate method and period of disposition.

The revenue requirements set forth in the Seven-Year Rate Plan assume the sale of a 15% undivided interest in the Kemper IGCC to SMEPA and utilization of bonus depreciation as provided by the American Taxpayer Relief Act of 2012 (ATRA), which currently requires that assets be placed in service in 2014. While Mississippi Power currently expects to place the combined cycle and the associated common facilities portion of the Kemper IGCC in service in the summer of 2014, extension of the in-service date for the remainder of the Kemper IGCC beyond 2014 results in the loss of tax benefits related to bonus depreciation under current law. The estimated value to retail customers of the bonus depreciation tax benefits not associated with the combined cycle and the associated common facilities portion of the Kemper IGCC is approximately $130 million to $160 million. See "Income Tax Matters – Bonus Depreciation" herein for additional information regarding bonus depreciation.

Mississippi Power plans to further revise the Seven-Year Rate Plan to reflect changes including the revised in-service date, the change in expected benefits relating to tax credits, various other revenue requirement items, and

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other tax matters, including bonus depreciation, which include ensuring compliance with the normalization requirements of the Internal Revenue Code. The impact of these revisions for the average annual retail revenue requirement is estimated to be an increase of approximately $50 million through 2020. The revision of the Seven-Year Rate Plan is also expected to reflect rate mitigation options identified by Mississippi Power that, if approved by the Mississippi PSC, would result in no change to the total customer rate impacts contemplated in the original Seven-Year Rate Plan.

Any further cost increases and/or extensions of the in-service date with respect to the Kemper IGCC could have an adverse impact on the Seven-Year Rate Plan, including the inability to recover items considered as Cost Cap Exceptions.

In the event that the Mississippi PSC does not approve or Mississippi Power withdraws the Seven-Year Rate Plan, as ultimately revised, Mississippi Power would seek rate recovery through an alternate means, which could include a traditional rate case.

Prudence Reviews

The Mississippi PSC's review of Kemper IGCC costs is ongoing. On August 5, 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. 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.

Regulatory Assets

Consistent with the treatment of non-capital costs incurred during the pre-construction period, the Mississippi PSC granted Mississippi Power the authority to defer all non-capital Kemper IGCC-related costs to a regulatory asset during the construction period, subject to review of such costs by the Mississippi PSC. The amortization period of 40 years proposed by Mississippi Power for any such costs approved for recovery remains subject to approval 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.

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, a wholly-owned subsidiary of The North American Coal Corporation (Liberty Fuels), which will develop, construct, and manage 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 will acquire, construct, and 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

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Mississippi Power does not satisfy its contractual obligation with respect to deliveries of captured CO₂ by May 11, 2015.

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 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 asset purchase agreement 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 asset purchase agreement whereby Mississippi Power and SMEPA agreed to amend the power supply agreement entered into by the parties in April 2011 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 April 2011 power supply agreement were $17.5 million in 2013. In December 2013, Mississippi Power and SMEPA agreed to extend SMEPA's option to purchase through December 31, 2014. The sale and transfer of an interest in the Kemper IGCC to SMEPA are subject to approval by the Mississippi PSC.

The closing of this transaction is conditioned upon execution of a joint ownership and operating agreement, receipt of all construction permits, appropriate regulatory approvals, financing, and other conditions. In 2012, SMEPA received a conditional loan commitment from Rural Utilities Service to provide funding for SMEPA's undivided interest in the Kemper IGCC.

In 2012 and on January 2, 2014, Mississippi Power received $150 million and $75 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 asset purchase agreement, or within 15 days of a request by SMEPA for a full or partial refund. Given the interest-bearing nature of the deposit and SMEPA's ability to request a refund, the deposits have been presented as a current liability in Mississippi Power's Condensed Balance Sheets herein and as financing proceeds in Mississippi Power's Condensed Statements of Cash Flows herein. In July 2013, Southern Company entered into an agreement with SMEPA under which Southern Company has agreed to guarantee the obligations of Mississippi Power with respect to any required refund of the deposits.

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

Income Tax Matters

Bonus Depreciation

In January 2013, the ATRA was signed into law. The ATRA retroactively extended several tax credits through 2013 and extended 50% bonus depreciation for property placed in service in 2013 (and for certain long-term production-period projects to be placed in service in 2014), which is currently expected to apply primarily to the combined cycle and associated common facilities portion of the Kemper IGCC. The estimated cash flow benefit of approximately $120 million is dependent upon placing the assets in service in 2014. As discussed in "Integrated Coal Gasification Combined Cycle" herein, the remainder of the Kemper IGCC, including the gasification system, would not qualify for bonus depreciation under the ATRA if placed in service after 2014.

Investment Tax Credits

The IRS allocated $133 million (Phase I) and $279 million (Phase II) of Internal Revenue Code Section 48A tax credits to Mississippi Power in connection with the Kemper IGCC. In May 2013, the IRS notified Mississippi Power that no additional tax credits under the Internal Revenue Code Section 48A Phase III were allocated to the Kemper IGCC. As a result of the schedule extension for the Kemper IGCC, the Phase I credits have been recaptured. Through June 30, 2014, Mississippi Power had recorded tax benefits totaling $276.4 million for the

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remaining Phase II credits, which 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. A portion of the Phase II tax credits will be subject to recapture upon completion of SMEPA's purchase of an undivided interest in the Kemper IGCC as described above.

The ultimate outcome of these matters 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 increased generally throughout the U.S. In particular, personal injury, property damage, and other claims for damages alleged to have been caused by CO₂ and other emissions, coal combustion residuals, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters, have become more frequent.

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 the Notes 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.

Sierra Club Settlement Agreement

On August 1, 2014, Mississippi Power entered into the Sierra Club Settlement Agreement that, among other things, requires the Sierra Club to dismiss or withdraw all pending legal and regulatory challenges of the Kemper IGCC and the scrubber project at Plant Daniel Units 1 and 2. In addition, the Sierra Club agreed to refrain from initiating, intervening in, and/or challenging certain legal and regulatory proceedings for the Kemper IGCC, including, but not limited to, the prudence review, and Plant Daniel for a period of three years from the date of the Sierra Club Settlement Agreement. On August 4, 2014, the Sierra Club filed all of the required motions necessary to dismiss or withdraw.

Under the Sierra Club Settlement Agreement, Mississippi Power agreed to, among other things, fund a $15 million grant payable over a five-year period for an energy efficiency and renewable program and contribute $2 million to a conservation fund. In addition, and consistent with Mississippi Power's ongoing evaluation of recent environmental rules and regulations, Mississippi Power agreed to retire, repower with natural gas, or convert to an alternative non-fossil fuel source Plant Sweatt Units 1 and 2 (80 MWs) no later than December 2018. Mississippi Power also agreed that it would cease burning coal and other solid fuel at Plant Watson Units 4 and 5 (750 MWs) and begin operating those units solely on natural gas no later than April 2015, and cease burning coal and other solid fuel at Plant Greene County Units 1 and 2 (200 MWs) and begin operating those units solely on natural gas no later than April 2016. See "PSC Matters – Environmental Compliance Overview Plan" herein for additional information.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 2014, Mississippi Power further extended the scheduled in-service date for the Kemper IGCC to the second quarter 2015 and 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 related costs 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 $380.0 million ($234.7 million after tax) in the first quarter 2014, $40.0 million ($24.7 million after tax) in the fourth quarter 2013, $150.0 million ($92.6 million after tax) in the third quarter 2013, $450.0 million ($277.9 million after tax) in the second quarter 2013, $462.0 million ($285.3 million after tax) in the first quarter 2013, and $78.0 million ($48.2 million after tax) in the fourth quarter 2012. In the aggregate, Mississippi Power has incurred charges of $1.56 billion ($963.3 million after tax) as a result of changes in the cost estimate for the Kemper IGCC through June 30, 2014.

Mississippi Power has experienced, and may continue to experience, material volatility 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 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, contract or supplier delay, non-performance under construction or other agreements, operational performance, operational readiness, unforeseen engineering or design problems, start-up activities for this first-of-a-kind technology (including major equipment failure and system integration), and/or operations.

Mississippi Power's revised cost estimate includes costs through May 31, 2015. Any further extension of the in-service date is currently estimated to result in additional costs of approximately $20 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.

Given the significant judgment involved in estimating the future costs to complete construction, 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.

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Recently Issued Accounting Standards

On May 28, 2014, the Financial Accounting Standards Board issued ASC 606, Revenue from Contracts with Customers. ASC 606 revises the accounting for revenue recognition and is effective for fiscal years beginning after December 15, 2016. Mississippi Power is currently evaluating the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined.

FINANCIAL CONDITION AND LIQUIDITY

Overview

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Mississippi Power in Item 7 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" herein for additional information. Although earnings for the six months ended June 30, 2014 were negatively affected by revisions to the cost estimate for the Kemper IGCC, Mississippi Power's financial condition remained stable at June 30, 2014. Through June 30, 2014, Mississippi Power has incurred non-recoverable cash expenditures of $925.0 million and is expected to incur approximately $635 million in additional non-recoverable cash expenditures through completion of the Kemper IGCC. During the first six months of 2014, Mississippi Power received $210.0 million in equity contributions and a $220.0 million loan from Southern Company. Mississippi 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. In addition, Mississippi Power may receive additional equity contributions or loans from Southern Company. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.

Net cash provided from operating activities totaled $178.2 million for the first six months of 2014, an increase of $55.8 million as compared to the corresponding period in 2013. The increase in cash provided from operating activities is primarily due to rate recovery related to the Kemper IGCC, a decrease in receivables, and increases in accounts payable and accrued compensation, partially offset by income taxes primarily related to the Kemper IGCC and an increase in under-recovered regulatory clause revenue. Net cash used for investing activities totaled $733.5 million for the first six months of 2014 primarily due to gross property additions related to the Kemper IGCC and the Plant Daniel scrubber project. Net cash provided from financing activities totaled $656.0 million for the first six months of 2014 primarily due to an increase in equity contributions and a loan from Southern Company, the issuance of bank notes, and the receipt of an interest-bearing refundable deposit related to a pending asset sale, partially offset by a return of paid in capital. 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 six months of 2014 include an increase in total property, plant, and equipment of $340.5 million and an increase in other regulatory liabilities, deferred of $72.9 million primarily due to the Kemper IGCC. Fossil fuel stock decreased $31.7 million primarily due to decreased coal inventories and other accrued taxes decreased $32.8 million primarily due to the payment of ad valorem taxes. Securities due within one year increased $412.4 million primarily due to bank loans maturing by the end of the second quarter 2015. Long-term debt increased $64.2 million primarily due to a $220.0 million loan from Southern Company and a bank loan of $250.0 million, partially offset by the reclassification of long-term bank loans to securities due within one year. The interest-bearing refundable deposit related to asset sale increased $75.0 million due to an additional deposit from SMEPA to be applied to the sale price for the pending sale of an undivided interest in the Kemper IGCC.

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,

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

scheduled maturities of long-term debt, as well as related interest, leases, purchase commitments, derivative obligations, preferred stock dividends, trust funding requirements, and unrecognized tax benefits. Approximately $426.2 million will be required through June 30, 2015 to fund maturities of long-term debt.

The construction program of Mississippi Power is currently estimated to be $1.6 billion for 2014, $461 million for 2015, and $249 million for 2016, which includes expenditures related to the construction and start-up of the Kemper IGCC of $1.3 billion for 2014 and $208 million for 2015. The amounts related to the construction and start-up of the Kemper IGCC exclude SMEPA's proposed acquisition of a 15% ownership share of the Kemper IGCC for approximately $572 million (including construction costs for all prior periods relating to its proposed ownership interest).

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 FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" and 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, short-term debt, and equity contributions or loans 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 Mississippi Power in Item 7 of the Form 10-K for additional information.

Mississippi Power has received $245.3 million of DOE Grants 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.

Mississippi Power's current liabilities frequently exceed current assets because of the continued use of short-term obligations 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.

At June 30, 2014, Mississippi Power had approximately $245.9 million of cash and cash equivalents. Committed credit arrangements with banks at June 30, 2014 were as follows:

Expires(a)										Executable Term Loans				Due Within One Year
2014		2015		2016		Total		Unused		One Year		Two Years		Term Out		No Term Out
(in millions)						(in millions)				(in millions)				(in millions)
$	40	$	95	$	165	$	300	$	300	$	25	$	40	$	65	$	70

(a) No credit arrangements expire in 2017 or 2018.

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MISSISSIPPI POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 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 arrangements contain material adverse change clauses at the time of borrowing. Mississippi Power expects to renew its credit arrangements, as needed prior to expiration.

A portion of the $300.0 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 June 30, 2014 was approximately $40.1 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.

Mississippi Power had no commercial paper or short-term debt outstanding during the three-month period ended June 30, 2014.

Management believes the need for working capital can be adequately met by utilizing commercial paper, equity contributions or loans from Southern Company, lines of credit, short-term bank notes, and cash.

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 June 30, 2014, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $226 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 January 2014, Mississippi Power entered into an 18-month floating rate bank loan bearing interest based on one-month LIBOR. The term loan was for $250 million aggregate principal amount, and proceeds were used for working capital and other general corporate purposes, including Mississippi Power's continuous construction program.

In 2012 and January 2014, Mississippi Power received $150 million and $75 million, respectively, of interest-bearing refundable deposits from SMEPA to be applied to the sale price for the pending sale of an undivided interest in the Kemper IGCC. Until the sale is closed, the deposits bear interest at Mississippi Power's AFUDC rate adjusted for income taxes, which was 10.132% per annum for the period ended June 30, 2014 and 9.932% per annum for 2013, and are refundable to SMEPA upon termination of the asset purchase agreement related to such purchase or within 15 days of a request by SMEPA for a full or partial refund. In July 2013, Southern Company

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

entered into an agreement with SMEPA under which Southern Company has agreed to guarantee the obligations of Mississippi Power with respect to any required refund of the deposits.

In May 2014, Mississippi Power issued a 19-month floating rate promissory note to Southern Company for a loan bearing interest based on one-month LIBOR. This loan was for $220 million aggregate principal amount and the proceeds were used for working capital and other general corporate purposes, including Mississippi Power's construction program.

Also in May 2014, the Mississippi Business Finance Corporation (MBFC) issued $12.3 million aggregate principal amount of MBFC Taxable Revenue Bonds (Mississippi Power Company Project), Series 2013A for the benefit of Mississippi Power and proceeds were used to reimburse Mississippi Power for the cost of the acquisition, construction, equipping, installation, and improvement of certain equipment and facilities for the lignite mining facility related to the Kemper IGCC. Any future issuances of the Series 2013A bonds will be used for this same purpose. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Financing Activities" of Mississippi Power in Item 7 of the Form 10-K for additional information.

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.

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SOUTHERN POWER COMPANY

AND SUBSIDIARY COMPANIES

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CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2014			2013			2014			2013
	(in thousands)						(in thousands)
Operating Revenues:
Wholesale revenues, non-affiliates	$	260,347		$	216,647		$	538,215		$	440,076
Wholesale revenues, affiliates	67,563			88,638			139,896			166,829
Other revenues	893			1,970			1,546			3,297
Total operating revenues	328,803			307,255			679,657			610,202
Operating Expenses:
Fuel	118,053			110,630			242,615			230,002
Purchased power, non-affiliates	16,594			22,307			44,487			36,880
Purchased power, affiliates	16,493			6,282			45,679			14,147
Other operations and maintenance	69,330			62,661			122,045			113,611
Depreciation and amortization	51,559			44,898			103,016			85,058
Taxes other than income taxes	5,701			5,453			11,384			10,807
Total operating expenses	277,730			252,231			569,226			490,505
Operating Income	51,073			55,024			110,431			119,697
Other Income and (Expense):
Interest expense, net of amounts capitalized	(21,966		)	(20,568		)	(43,969		)	(40,962		)
Other income (expense), net	(32		)	(1,691		)	85			(1,948		)
Total other income and (expense)	(21,998		)	(22,259		)	(43,884		)	(42,910		)
Earnings Before Income Taxes	29,075			32,765			66,547			76,787
Income taxes (benefit)	(2,969		)	4,843			217			19,673
Net Income	32,044			27,922			66,330			57,114
Less: Net income attributable to noncontrolling interest	1,232			—			2,047			—
Net Income Attributable to Southern Power Company	$	30,812		$	27,922		$	64,283		$	57,114

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2014		2013		2014		2013
	(in thousands)				(in thousands)
Net Income	$	32,044	$	27,922	$	66,330	$	57,114
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $1, $-, $- and $-, respectively	2		—		—		—
Reclassification adjustment for amounts included in net income, net of tax of $24, $1,052, $63 and $2,097, respectively	108		1,647		197		3,281
Total other comprehensive income (loss)	110		1,647		197		3,281
Less: Comprehensive income attributable to noncontrolling interest	1,232		—		2,047		—
Comprehensive Income Attributable to Southern Power Company	$	30,922	$	29,569	$	64,480	$	60,395

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

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Six Months Ended June 30,
	2014			2013
	(in thousands)
Operating Activities:
Net income	$	66,330		$	57,114
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	100,111			90,351
Deferred income taxes	(3,162		)	13,693
Investment tax credits	26,134			16,443
Deferred revenues	(24,342		)	(23,444		)
Other, net	7,893			11,909
Changes in certain current assets and liabilities —
-Receivables	(34,252		)	(23,335		)
-Fossil fuel stock	(1,006		)	(377		)
-Materials and supplies	(3,126		)	(2,560		)
-Prepaid income taxes	21,406			(19,747		)
-Other current assets	2,051			2,725
-Accounts payable	23,593			(7,580		)
-Accrued taxes	7,095			21,048
-Accrued interest	94			(41		)
-Other current liabilities	5,027			(390		)
Net cash provided from operating activities	193,846			135,809
Investing Activities:
Plant acquisition	(213,470		)	(111,600		)
Property additions	(11,048		)	(252,271		)
Change in construction payables	(3,426		)	106,795
Payments pursuant to long-term service agreements	(22,677		)	(22,469		)
Investment in restricted cash	—			(20,000		)
Other investing activities	(10,860		)	(206		)
Net cash used for investing activities	(261,481		)	(299,751		)
Financing Activities:
Increase in notes payable, net	73,482			195,142
Proceeds —
Capital contributions	(3,417		)	1,394
Other long-term debt	9,941			10,249
Repayments — Other long-term debt	(818		)	(220		)
Distributions to noncontrolling interest	(150		)	(146		)
Contributions from noncontrolling interest	7,166			7,683
Payment of common stock dividends	(65,560		)	(64,560		)
Other financing activities	1,863			675
Net cash provided from financing activities	22,507			150,217
Net Change in Cash and Cash Equivalents	(45,128		)	(13,725		)
Cash and Cash Equivalents at Beginning of Period	68,744			28,592
Cash and Cash Equivalents at End of Period	$	23,616		$	14,867
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $(113) and $- capitalized for 2014 and 2013, respectively)	$	42,745		$	34,924
Income taxes, net	(59,148		)	(3,799		)
Noncash transactions — accrued property additions at end of period	5,297			136,998

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

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CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

Assets	At June 30, 2014		At December 31, 2013
	(in thousands)
Current Assets:
Cash and cash equivalents	$	23,616	$	68,744
Receivables —
Customer accounts receivable	106,162		73,497
Other accounts receivable	8,041		3,983
Affiliated companies	36,257		38,391
Fossil fuel stock, at average cost	20,414		19,178
Materials and supplies, at average cost	57,906		54,780
Prepaid service agreements—current	29,676		81,206
Prepaid income taxes	77,488		54,732
Other prepaid expenses	5,769		7,915
Assets from risk management activities	289		182
Total current assets	365,618		402,608
Property, Plant, and Equipment:
In service	4,942,635		4,696,134
Less accumulated provision for depreciation	922,461		871,963
Plant in service, net of depreciation	4,020,174		3,824,171
Construction work in progress	10,237		9,843
Total property, plant, and equipment	4,030,411		3,834,014
Other Property and Investments:
Goodwill	1,839		1,839
Other intangible assets, net of amortization of $6,851 and $5,614 at June 30, 2014 and December 31, 2013, respectively	42,269		43,505
Total other property and investments	44,108		45,344
Deferred Charges and Other Assets:
Prepaid long-term service agreements	69,326		73,676
Other deferred charges and assets — affiliated	7,767		4,605
Other deferred charges and assets — non-affiliated	87,814		68,853
Total deferred charges and other assets	164,907		147,134
Total Assets	$	4,605,044	$	4,429,100

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

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CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholder's Equity	At June 30, 2014		At December 31, 2013
	(in thousands)
Current Liabilities:
Securities due within one year	$	2,082	$	599
Notes payable — non-affiliated	73,482		—
Accounts payable —
Affiliated	80,052		56,661
Other	18,031		20,747
Accrued taxes —
Accrued income taxes	1,585		161
Other accrued taxes	10,052		2,662
Accrued interest	28,446		28,352
Other current liabilities	22,786		18,492
Total current liabilities	236,516		127,674
Long-term Debt	1,626,908		1,619,241
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	727,923		724,390
Accumulated deferred investment tax credits	398,397		340,269
Deferred capacity revenues — affiliated	6,629		15,279
Other deferred credits and liabilities — affiliated	1,113		1,621
Other deferred credits and liabilities — non-affiliated	10,261		7,896
Total deferred credits and other liabilities	1,144,323		1,089,455
Total Liabilities	3,007,747		2,836,370
Redeemable Noncontrolling Interest	37,841		28,778
Common Stockholder's Equity:
Common stock, par value $.01 per share —
Authorized — 1,000,000 shares
Outstanding — 1,000 shares	—		—
Paid-in capital	1,025,618		1,029,035
Retained earnings	530,722		531,998
Accumulated other comprehensive income	3,116		2,919
Total common stockholder's equity	1,559,456		1,563,952
Total Liabilities and Stockholder's Equity	$	4,605,044	$	4,429,100

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

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

SECOND QUARTER 2014 vs. SECOND QUARTER 2013

AND

YEAR-TO-DATE 2014 vs. YEAR-TO-DATE 2013

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.

On April 17, 2014, Southern Power and Turner Renewable Energy, LLC (TRE), through Southern Turner Renewable Energy, LLC (STR), a jointly-owned subsidiary owned 90% by Southern Power, acquired all of the outstanding membership interests of Adobe Solar, LLC (Adobe). Adobe constructed and owns an approximately 20-MW solar photovoltaic facility in Kern County, California. The solar facility began commercial operation on May 21, 2014 and serves a PPA with Southern California Edison Company (SCE) covering the entire output of the plant through 2034.

On May 22, 2014, Southern Power and TRE, through STR, acquired all of the outstanding membership interests of Macho Springs Solar, LLC (Macho Springs). Macho Springs constructed and owns an approximately 50-MW solar photovoltaic facility in Luna County, New Mexico. The solar facility began commercial operation on May 23, 2014 and serves a PPA with El Paso Electric Company (EPE) covering the entire output of the plant through 2034.

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. These indicators include 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

Second Quarter 2014 vs. Second Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$2.9	10.4	$7.2	12.6

Net income attributable to Southern Power for the second quarter 2014 was $30.8 million compared to $27.9 million for the corresponding period in 2013. Net income for year-to-date 2014 was $64.3 million compared to $57.1 million for the corresponding period in 2013. The increases were primarily due to an increase in energy revenues from non-affiliates and a decrease in income taxes, partially offset by increases in other operations and maintenance expenses and depreciation.

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Wholesale Revenues–Non-Affiliates

Second Quarter 2014 vs. Second Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$43.7	20.2	$98.1	22.3

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.

Wholesale revenues from non-affiliates for the second quarter 2014 were $260.3 million compared to $216.6 million for the corresponding period in 2013. The increase was due to a $49.0 million increase in energy sales, primarily as a result of new solar PPAs and requirements contracts and increased revenue from existing contracts and uncovered units primarily as a result of higher demand, partially offset by a $5.3 million decrease in capacity revenues. The increase in energy sales reflects a 33.8% increase in KWH sales and an 8.4% increase in the average price of energy.

Wholesale revenues from non-affiliates for year-to-date 2014 were $538.2 million compared to $440.1 million for the corresponding period in 2013. The increase was due to a $103.7 million increase in energy sales, primarily as a result of increased revenue under existing contracts, new solar PPAs and requirements contracts and additional revenue from uncovered units primarily as a result of higher demand, partially offset by a $5.6 million decrease in capacity revenues. The increase in energy sales reflects a 25.8% increase in the average price of energy and a 15.3% increase in KWH sales.

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Power Sales Agreements" of Southern Power in Item 7 of the Form 10-K for additional information.

Wholesale Revenues–Affiliates

Second Quarter 2014 vs. Second Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$(21.0)	(23.8)	$(26.9)	(16.1)

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 second quarter 2014were $67.6 million compared to $88.6 million for the corresponding period in 2013. The decrease was primarily the result of a $22.7 million decrease in energy sales under the IIC, reflecting a 34.8% decrease in KWH sales, primarily as a result of higher natural gas prices and the availability of lower cost affiliate power. This decrease was partially offset by a $2.7 million increase in energy sales under existing PPAs, reflecting a 42.1% increase in the average price of energy, primarily as a result of higher natural gas prices.

Wholesale revenues from affiliates for year-to-date 2014 were $139.9 million compared to $166.8 million for the corresponding period in 2013. The decrease was primarily the result of a $32.3 million decrease in energy sales under the IIC, reflecting a 40.5% decrease in KWH sales, primarily as a result of higher natural gas prices and the availability of lower cost affiliate power. This decrease was partially offset by a $6.4 million increase in energy sales under existing PPAs, reflecting a 70.0% increase in the average price of energy, primarily as a result of higher natural gas prices.

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Power Sales Agreements" of Southern Power in Item 7 of the Form 10-K for additional information.

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Fuel and Purchased Power Expenses

	Second Quarter 2014 vs. Second Quarter 2013				Year-to-Date 2014 vs. Year-to-Date 2013
	(change in millions)			(% change)	(change in millions)		(% change)
Fuel	$	7.4		6.7	$	12.6	5.5
Purchased power – non-affiliates	(5.7		)	(25.6)	7.6		20.6
Purchased power – affiliates	10.2			162.5	31.6		222.9
Total fuel and purchased power expenses	$	11.9			$	51.8

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.

In the second quarter 2014, total fuel and purchased power expenses were $151.1 million compared to $139.2 million for the corresponding period in 2013. Fuel and purchased power expenses increased $11.9 million reflecting a 14.6% increase in the average cost of natural gas and a 31.5% increase in the volume of KWHs purchased primarily as a result of higher natural gas prices and the availability of lower cost affiliate power.

For year-to-date 2014, total fuel and purchased power expenses were $332.8 million compared to $281.0 million for the corresponding period in 2013. Fuel and purchased power expenses increased $62.6 million reflecting a 33.7% increase in the average cost of natural gas and a 43.7% increase in the volume of KWHs purchased primarily as a result of higher natural gas prices and the availability of lower cost affiliate power. This increase was partially offset by a $10.8 million decrease associated with the volume of KWHs generated.

In the second quarter 2014, fuel expense was $118.0 million compared to $110.6 million for the corresponding period in 2013. The increase was due to a $9.4 million increase associated with the higher average cost of fuel per KWH generated primarily due to the average cost of natural gas, partially offset by a $2.0 million decrease associated with the volume of KWHs generated primarily as a result of higher natural gas prices and the availability of lower cost affiliate power.

For year-to-date 2014, fuel expense was $242.6 million compared to $230.0 million for the corresponding period in 2013. The increase was due to a $45.7 million increase associated with the higher average cost of fuel per KWH generated primarily due to the average cost of natural gas, partially offset by a $33.1 million decrease associated with the volume of KWHs generated primarily as a result of higher natural gas prices and the availability of lower cost affiliate power.

In the second quarter 2014, purchased power expense was $33.1 million compared to $28.6 million for the corresponding period in 2013. The increase was due to a $9.0 million increase associated with the volume of KWHs purchased primarily as a result of higher natural gas prices and the availability of lower cost affiliate power. This increase was partially offset by a $4.5 million decrease associated with the average cost of purchased power.

For year-to-date 2014, purchased power expense was $90.2 million compared to $51.0 million for the corresponding period in 2013. The increase was due to a $22.3 million increase associated with the volume of KWHs purchased and a $16.9 million increase associated with the average cost of purchased power, primarily as a result of higher natural gas prices and the availability of lower cost affiliate power.

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Other Operations and Maintenance Expenses

Second Quarter 2014 vs. Second Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$6.6	10.6	$8.4	7.4

In the second quarter 2014, other operations and maintenance expenses were $69.3 million compared to $62.7 million for the corresponding period in 2013. For year-to-date 2014, other operations and maintenance expenses were $122.0 million compared to $113.6 million for the corresponding period in 2013. The increases were primarily due to scheduled outage and maintenance related costs as well as costs associated with the acquisition of new solar plants.

Depreciation and Amortization

Second Quarter 2014 vs. Second Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$6.7	14.8	$17.9	21.1

In the second quarter 2014, depreciation and amortization was $51.6 million compared to $44.9 million for the corresponding period in 2013. For year-to-date 2014, depreciation and amortization was $103.0 million compared to $85.1 million for the corresponding period in 2013. The increases were primarily due to an increase in depreciation expense related to Plants Campo Verde and Spectrum placed in service in the second half of 2013 and equipment retirements resulting from accelerated outage work.

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

Income Taxes (Benefit)

Second Quarter 2014 vs. Second Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$(7.8)	(161.3)	$(19.5)	(98.9)

In the second quarter 2014, income taxes (benefit) were $(3.0) million compared to income taxes of $4.8 million for the corresponding period in 2013. The change was primarily due to the impact of state apportionment changes reducing Southern Power's deferred tax liabilities resulting from the addition of new plants placed in service in 2014 and 2013, a change to the income tax filing method for North Carolina, and beneficial changes in certain state income tax laws.

For year-to-date 2014, income taxes (benefit) were $0.2 million compared to $19.7 million for the corresponding period in 2013. The change was primarily due to the impact of state apportionment changes reducing Southern Power's deferred tax liabilities resulting from the addition of new plants placed in service in 2014 and 2013, a change to the income tax filing method for North Carolina, an increase in state income tax credits, beneficial changes in certain state income tax laws, and lower pre-tax income.

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

FUTURE EARNINGS POTENTIAL

The results of operations discussed above are not necessarily indicative of Southern Power's future earnings potential. The level of Southern Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Southern Power's competitive wholesale business. These factors include: Southern Power's ability to achieve sales growth while containing costs; regulatory matters; creditworthiness of customers; total generating capacity available in Southern Power's target market areas; the successful remarketing of capacity as

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

current contracts expire; and Southern Power's ability to execute its acquisition and value creation strategy and to construct generating facilities.

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.

Environmental Statutes and Regulations

Air Quality

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Air Quality" of Southern Power in Item 7 of the Form 10-K for additional information regarding the Cross State Air Pollution Rule (CSAPR) and the EPA's proposed rules regarding the regulation of excess emissions during periods of startup, shutdown, or malfunction (SSM).

On April 29, 2014, the U.S. Supreme Court overturned the U.S. Court of Appeals for the District of Columbia Circuit's August 2012 decision to vacate CSAPR and remanded the case back to the U.S. Court of Appeals for the District of Columbia Circuit for further proceedings. On June 26, 2014, the EPA requested that the U.S. Court of Appeals for the District of Columbia Circuit lift the stay on CSAPR and approve a revised schedule with compliance to begin on January 1, 2015.

On June 10, 2014, the EPA entered into a revised settlement agreement requiring it to issue a supplemental proposed SSM rule by September 5, 2014 and finalize the proposed rule by May 22, 2015.

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

Water Quality

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Water Quality" of Southern Power in Item 7 of the Form 10-K for additional information regarding the EPA's rulemaking for cooling water intake structures.

On May 19, 2014, the EPA signed a final rule establishing standards for reducing effects on fish and other aquatic life caused by new and existing cooling water intake structures at existing power plants and manufacturing facilities. The ultimate outcome of this final rule will depend on the results of additional studies and implementation of the rule by state regulators, but could result in additional capital and operational costs associated with changes to existing intake structures and cooling systems and increased costs associated with the construction of new generating units. The ultimate impact of this rule will depend on the outcome of any legal challenges and cannot be determined at this time.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Global Climate Issues

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues" of Southern Power in Item 7 of the Form 10-K for additional information regarding the EPA's current and proposed regulation of GHG emissions under the Clean Air Act.

On June 18, 2014, the EPA published the proposed Clean Power Plan, setting forth guidelines for states to develop plans to address CO₂ emissions from existing fossil fuel-fired electric generating units. The EPA's proposed guidelines establish state-specific interim and final CO₂ emission rate goals to be achieved between 2020 and 2029 and in 2030 and thereafter. The EPA also published the proposed CO₂ performance standards for modified and reconstructed fossil fuel-fired electric generating units. If finalized as proposed, the proposed guidelines and standards could result in operational restrictions and material compliance costs. Also, additional compliance costs could affect results of operations, cash flows, and financial condition if such costs are not recovered through market-based contracts. The ultimate impact of these proposals will depend on the specific requirements of the final guidelines and performance standards, implementation by states, and the outcome of any legal challenges and cannot be determined at this time.

On June 23, 2014, the U.S. Supreme Court struck down a portion of the EPA's program for GHG permitting under the Prevention of Significant Deterioration and Title V operating permit programs, holding that a facility's GHG emissions alone could not trigger a requirement to obtain a permit and that the EPA did not have the authority to tailor the statutory permitting thresholds. The ultimate impact of this decision cannot be determined at this time.

Acquisitions

Adobe Solar, LLC

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Acquisitions" of Southern Power in Item 7 of the Form 10-K and Note (I) to the Condensed Financial Statements herein for additional information.

On April 17, 2014, Southern Power and TRE, through STR, acquired all of the outstanding membership interests of Adobe from Sun Edison, LLC, the original developer of the project. Adobe constructed and owns an approximately 20-MW solar photovoltaic facility in Kern County, California. The solar facility began commercial operation on May 21, 2014 and has the entire output of the plant contracted under a 20-year PPA with SCE.

Macho Springs Solar, LLC

On May 22, 2014, Southern Power and TRE, through STR, acquired all of the outstanding membership interests of Macho Springs from First Solar Development, LLC, the original developer of the project. Macho Springs constructed and owns an approximately 50-MW solar photovoltaic facility in Luna County, New Mexico. The solar facility began commercial operation on May 23, 2014 and has the entire output of the plant contracted under a 20-year PPA with EPE.See Note (I) to the Condensed Financial Statements herein for additional information.

Power Sales Agreements

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Power Sales Agreements" of Southern Power in Item 7 of the Form 10-K for additional information regarding Southern Power's PPAs with investor-owned utilities, independent power purchasers, municipalities, and electric cooperatives.

On February 28, 2014, GreyStone Power Corporation and Jackson Electric Membership Corporation exercised their rights to reduce their contracted capacities by 5 MWs each as provided for in the applicable PPAs.

As discussed above, on April 17, 2014 and May 22, 2014, a subsidiary of Southern Power assumed PPAs with SCE and EPE in connection with the acquisitions of Adobe and Macho Springs, respectively. See Note (I) to the Condensed Financial Statements herein for additional information.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 increased generally throughout the U.S. In particular, personal injury, property damage, and other 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, have become more frequent.

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.

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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

Recently Issued Accounting Standards

On May 28, 2014, the Financial Accounting Standards Board issued ASC 606, Revenue from Contracts with Customers. ASC 606 revises the accounting for revenue recognition and is effective for fiscal years beginning after December 15, 2016. Southern Power is currently evaluating the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined.

FINANCIAL CONDITION AND LIQUIDITY

Overview

Southern Power's financial condition remained stable at June 30, 2014. Southern Power intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements as needed to meet future capital and liquidity needs. See "Sources of Capital" herein for additional information on lines of credit.

Net cash provided from operating activities totaled $193.8 million for the first six months of 2014, an increase of $58.0 million as compared to the first six months of 2013. The increase in cash provided from operating activities was primarily due to cash received for ITCs related to Plants Nacogdoches, Apex, Campo Verde, and Spectrum and an increase in affiliated accounts payable. Net cash used for investing activities totaled $261.5 million for the first six months of 2014 primarily due to expenditures related to the acquisitions of Adobe and Macho Springs and payments pursuant to long-term service agreements. Net cash provided from financing activities totaled $22.5 million for the first six months of 2014 primarily due to the issuance of commercial paper and an increase in long-term debt related to the acquisitions of Adobe and Macho Springs. This was partially offset by the payment of common stock dividends. Fluctuations in cash flow from financing activities vary year to year based on capital

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

needs and the maturity or redemption of securities.

Significant balance sheet changes for the first six months of 2014 include a $196.0 million increase in plant in service, net of depreciation primarily due to the acquisitions of Adobe and Macho Springs. Other significant changes include a $73.5 million increase in notes payable due to the issuance of commercial paper, a $58.1 million increase in accumulated deferred investment tax credits primarily due to the acquisitions of Adobe and Macho Springs placed in service in 2014, and a $23.4 million increase in affiliated accounts payable.

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. There are no maturities of long-term debt through June 30, 2015.

The construction 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 due to market opportunities and Southern Power's ability to execute its growth strategy. Actual construction 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 may use operating cash flows, external funds, or equity capital or loans from Southern Company to finance any new projects, acquisitions, and ongoing capital requirements. Southern Power expects to generate external funds from the issuance of unsecured senior debt and commercial paper or utilization of credit arrangements from banks. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Southern Power in Item 7 of the Form 10-K for additional information.

Southern Power's current liabilities sometimes exceed current assets due to the use of short-term debt as a funding source, as well as cash needs, which can fluctuate significantly due to the seasonality of the business.

To meet liquidity and capital resource requirements, Southern Power had at June 30, 2014 cash and cash equivalents of approximately $23.6 million and Southern Power Company had a committed credit facility of $500 million (Facility) expiring in 2018, of which $499 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 Company. 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 Company'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.

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

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Details of short-term borrowings were as follows:

	Commercial Paper at the End of the Period				Commercial Paper During the Period(a)
	Amount Outstanding		Weighted Average Interest Rate		Average Outstanding		Weighted Average Interest Rate		Maximum Amount Outstanding
	(in millions)				(in millions)				(in millions)
June 30, 2014:	$	73	0.3	%	$	33	0.3	%	$	98

(a) Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 2014.

Management believes the need for working capital can be adequately met by utilizing the commercial paper program, the Facility, short-term bank notes, and cash.

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 June 30, 2014 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	992

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 Company'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's credit. The PPA requires credit assurances without stating a specific credit rating. The amount of collateral required would depend upon actual losses, if any, resulting from a credit downgrade.

Financing Activities

During the six months ended June 30, 2014, Southern Power prepaid $0.8 million of long-term debt payable to TRE and issued $3.8 million due April 30, 2034, $5.3 million due May 31, 2034, and an additional $0.8 million due April 30, 2033 under promissory notes payable to TRE related to the financing of Adobe, Macho Springs, and Campo Verde Solar, LLC, respectively.

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	134
B	Contingencies and Regulatory Matters	134
C	Fair Value Measurements	150
D	Stockholders' Equity	155
E	Financing	157
F	Retirement Benefits	159
G	Effective Tax Rate	162
H	Derivatives	162
I	Acquisitions	169
J	Segment and Related Information	170

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, 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, 2013 have been derived from the audited financial statements of each registrant. In the opinion of each registrant's management, the information regarding such registrant furnished herein reflects all adjustments, which, except as otherwise disclosed, are of a normal recurring nature, necessary to present fairly the results of operations for the periods ended June 30, 2014 and 2013. 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.

Depreciation

Beginning in 2014, Southern Power changed the method of depreciation for its property, plant, and equipment from composite depreciation to component depreciation. As a result, certain generation assets are depreciated on a units-of-production basis to better match outage and maintenance costs to the usage of, and revenues from, these assets. The difference in depreciation expense under this method was not material in the first and second quarters 2014 and is not expected to have a material impact on the financial statements of Southern Company or Southern Power in future periods.

Recently Issued Accounting Standards

On May 28, 2014, the Financial Accounting Standards Board issued ASC 606, Revenue from Contracts with Customers. ASC 606 revises the accounting for revenue recognition and is effective for fiscal years beginning after December 15, 2016. The registrants are currently evaluating the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined.

(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

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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 increased generally throughout the U.S. In particular, personal injury, property damage, and other claims for damages alleged to have been caused by CO₂ and other emissions, coal combustion residuals, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters, have become more frequent.

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 September 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 June 30, 2014 was $19 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

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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 February 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. In May 2013, the plaintiffs appealed the U.S. District Court for the Eastern District of North Carolina Western Division's order to the U.S. Court of Appeals for the Fourth Circuit.

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 $50 million as of June 30, 2014. 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, there was no impact on net income as a result of these liabilities.

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 December 2013 and, on March 28, 2014, the impacted utilities, including Mississippi Power, agreed to commence remediation actions on the site. Mississippi Power's environmental remediation liability is $0.6 million as of June 30, 2014 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 have pursued and continue to pursue legal remedies against the U.S. government for its partial breach of contract.

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As a result of the first lawsuit, Georgia Power recovered approximately $27 million, based on its ownership interests, and Alabama Power recovered approximately $17 million, representing the vast majority of the Southern Company system's direct costs of the expansion of spent nuclear fuel storage facilities at Plants Farley and Hatch and Plant Vogtle Units 1 and 2 from 1998 through 2004. In 2012, Alabama Power credited the award to cost of service for the benefit of customers. Also in 2012, Georgia Power credited the award to accounts where the original costs were charged and used it to reduce rate base, fuel, and cost of service for the benefit of customers.

In 2008 and again on March 4, 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, 2005 through December 31, 2010 and from January 1, 2011 through December 31, 2013, respectively. Damages will continue to accumulate until the issue is resolved or storage is provided. 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.

An on-site dry storage facility at Plant Vogtle Units 1 and 2 began operation in October 2013. At Plants Hatch and Farley, on-site dry spent fuel storage facilities are also operational. Facilities at all plants can be expanded to accommodate spent fuel through the expected life of each plant.

FERC Matters

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 the authority to defer in a regulatory asset costs related to the retirement or partial retirement of generating units as a result of environmental compliance rules. See Note 3 to the financial statements of Southern Company under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K, Note 3 to the financial statements of 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, 2014, Mississippi Power reached a settlement agreement with its wholesale customers and filed a request with the FERC for an increase in the Municipal and Rural Associations (MRA) cost-based electric tariff. The settlement agreement, approved by the FERC on May 20, 2014, provides that base rates under the MRA cost-based electric tariff will increase approximately $10.1 million annually, with revised rates effective for services rendered beginning May 1, 2014. The amount of base rate revenues to be received in 2014 from the agreed upon increase is expected to be approximately $6.9 million.

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	June 30, 2014		December 31, 2013
		(in millions)
Rate CNP Environmental – Under	Deferred under recovered regulatory clause revenues	$	32	$	7
Rate CNP PPA – Under	Deferred under recovered regulatory clause revenues	33		18
Retail Energy Cost Recovery – Over	Other regulatory liabilities, current	19		27
	Deferred over recovered regulatory clause revenues	—		15
Natural Disaster Reserve	Other regulatory liabilities, deferred	87		96

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Georgia Power

Renewables Development

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

On May 20, 2014, the Georgia PSC approved Georgia Power's application for the certification of two PPAs executed in April 2013 for the purchase of energy from two wind farms in Oklahoma with capacity totaling 250 MWs that will begin in 2016 and end in 2035.

As a result of amendments executed subsequent to June 30, 2014, the biomass PPAs classified as non-affiliate capital leases with related long-term obligations totaling $641 million as of December 31, 2013, no longer meet the definition of a lease or will be accounted for as operating leases. Due to these amendments, non-affiliate operating lease obligations increased by $127 million. As a result of additional amendmentsexecuted prior to June 30, 2014, commitments related to non-affiliate operating leases increased by a total of $23 million. As such, estimated total long-term obligations for non-affiliate operating leases have been updated to $116 million for 2015, $149 million for 2016, $150 million for 2017, $152 million for 2018 and $1.7 billion for 2019 and thereafter. Estimated long-term obligations did not change for 2014. The counterparties of the aforementioned PPAs have posted collateral as required. See Note 7 to the financial statements of Georgia Power under "Commitments – Fuel and Purchased Power Agreements" in Item 8 of the Form 10-K for additional information.

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.

Georgia Power filed a request with the Georgia PSC on January 10, 2014 to cancel the proposed biomass fuel conversion of Plant Mitchell Unit 3 (155 MWs) because it would not be cost effective for customers. On July 1, 2014, the Georgia PSC approved Georgia Power's request. The January 10, 2014 filing also notified the Georgia PSC of Georgia Power's plan to seek decertification later this year. Georgia Power now expects to request decertification of Plant Mitchell Unit 3 in connection with the triennial Integrated Resource Plan in 2016. Georgia Power plans to continue to operate the unit as needed until the Mercury and Air Toxics Standards rule becomes effective in April 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 June 30, 2014, Georgia Power's under recovered fuel balance totaled $244 million and is included in deferred charges and other assets on Southern Company's and Georgia Power's Condensed Balance Sheets herein. The under recovered fuel balance exceeded the $200 million threshold, triggering the Interim Fuel Rider mechanism. Therefore, on July 7, 2014, Georgia Power filed a plan with the Georgia PSC recommending that the Georgia PSC defer any action on the under recovered fuel balance until the next fuel case which is expected to be filed by February 27, 2015. The Georgia PSC took no action on Georgia Power's filing within 30 days; therefore, the existing fuel rates remain in place. As of December 31, 2013, Georgia Power's over recovered fuel balance totaled $58 million and is included in current liabilities and other deferred credits and liabilities on Southern Company's and Georgia Power's Condensed Balance Sheets herein.

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

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not have a significant effect on Southern Company's or Georgia Power's revenues or net income, but will affect cash flow.

Storm Damage Recovery

See Note 1 to the financial statements of Georgia Power under "Storm Damage Recovery" in Item 8 of the Form 10-K for additional information.

Georgia Power defers and recovers certain costs related to damages from major storms as mandated by the Georgia PSC. As of June 30, 2014 and December 31, 2013, the balance in the regulatory asset related to storm damage was $107 million and $37 million, respectively.

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, the eighth Vogtle Construction Monitoring (VCM) report, the ninth/tenth VCM report, and pending litigation.

In 2008, Georgia Power, acting for itself and as agent for the 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 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. Each 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%. The Vogtle 3 and 4 Agreement provides for liquidated damages upon the Contractor's failure to fulfill the schedule and performance guarantees. The Contractor's liability to the Owners for schedule and performance liquidated damages and warranty claims is subject to a cap.

Certain payment obligations of Westinghouse and Stone & Webster, Inc. under the Vogtle 3 and 4 Agreement are guaranteed by Toshiba Corporation and The Shaw Group, Inc., respectively. In the event of certain credit rating downgrades of any Owner, such Owner will be required to provide a letter of credit or other credit enhancement. The Owners may terminate the Vogtle 3 and 4 Agreement at any time for their convenience, provided that the Owners will be required to pay certain termination costs. The Contractor may terminate the Vogtle 3 and 4 Agreement under certain circumstances, including certain 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 Owners, 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 2009, the Georgia PSC approved inclusion of the Plant Vogtle Units 3 and 4 related CWIP accounts in rate base, and the State of Georgia enacted the Georgia Nuclear Energy Financing Act, which allows Georgia Power to recover financing costs for nuclear construction projects certified by the Georgia PSC. Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff by including the related CWIP accounts in rate base during the construction period. The Georgia PSC approved increases to the NCCR tariff of approximately $223 million, $35 million, $50 million, and $60 million, effective January 1, 2011, 2012, 2013, and 2014, respectively. Through the NCCR tariff, Georgia Power is collecting and amortizing to earnings approximately $91 million of financing costs, capitalized in 2009 and 2010, over the five-year period ending

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December 31, 2015, in addition to the ongoing financing costs. At June 30, 2014, approximately $27 million of these 2009 and 2010 costs remained unamortized in CWIP.

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. Accordingly, Georgia Power's eighth VCM report filed in February 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 September 2013, the Georgia PSC approved a 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. In accordance with the Georgia Integrated Resource Planning Act, any costs incurred by Georgia Power in excess of the certified amount will not be included in rate base, unless shown to be reasonable and prudent. In addition, financing costs on any excess construction-related costs potentially would be subject to recovery through AFUDC instead of the NCCR tariff. In accordance with the stipulation, Georgia Power filed with the Georgia PSC on February 28, 2014 a combined ninth and tenth VCM report covering the period from January 1 through December 31, 2013 (Ninth/Tenth VCM report), which requested approval for an additional $0.4 billion of construction capital costs. The Ninth/Tenth VCM report reflects estimated in-service construction capital costs of $4.8 billion and associated financing costs during the construction period, which are estimated to total approximately $2.0 billion. Georgia Power will resume filing semi-annual reports with the eleventh VCM report filing in late August 2014.

In 2012, the 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 Owners are responsible for these costs under the terms of the Vogtle 3 and 4 Agreement. Also in 2012, Georgia Power and the other Owners filed suit against the Contractor in the U.S. District Court for the Southern District of Georgia seeking a declaratory judgment that the Owners are not responsible for these costs. Later in 2012, the Contractor filed suit against Georgia Power and the other Owners in the U.S. District Court for the District of Columbia alleging the Owners are responsible for these costs. In August 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. The Contractor appealed the decision to the U.S. Court of Appeals for the District of Columbia Circuit in September 2013. 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 has asserted it is entitled to further schedule extensions. On May 22, 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 have 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 claimed amounts relating to these new allegations, but such additional claimed amounts could be substantial. Georgia Power has not agreed with either the proposed cost or schedule adjustments or that the Owners have any responsibility for costs related to these issues. While litigation is ongoing and Georgia Power intends to vigorously defend its positions, Georgia Power also expects negotiations with the Contractor to continue with respect to cost and schedule during which negotiations the parties may reach a mutually acceptable compromise of their positions.

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

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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 Owners or the Contractor or to both.

As construction continues, the risk remains that additional challenges in the 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. Additional claims by the Contractor or Georgia Power (on behalf of the 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 $5.4 million reduction in depreciation expense in the first six months of 2014.

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	June 30, 2014		December 31, 2013
		(in millions)
Fuel Cost Recovery – Under	Under recovered regulatory clause revenues	$	43.4	$	21.0
Purchased Power Capacity Recovery – Over	Other regulatory liabilities, current	9.1		—
Purchased Power Capacity Recovery – Under	Under recovered regulatory clause revenues	—		2.8
Environmental Cost Recovery – Under	Under recovered regulatory clause revenues	15.1		14.4
Energy Conservation Cost Recovery – Under	Under recovered regulatory clause revenues	4.9		7.0

Retail Fuel Cost Recovery

See Note 1 and Note 3 to the financial statements of Gulf Power under "Revenues" and "Retail Regulatory Matters – Fuel Cost Recovery," respectively, in Item 8 of the Form 10-K for additional information.

Gulf Power has established fuel cost recovery rates as approved annually by the Florida PSC. In late 2013 and the first six months of 2014, Gulf Power experienced higher than expected costs for natural gas and purchased power along with lower fuel revenues for non-territorial sales. If the projected year-end fuel cost over or under recovery balance exceeds 10% of the projected fuel revenues for the period, Gulf Power is required to notify the Florida PSC and indicate if an adjustment to the fuel recovery factor is being requested. Gulf Power filed such notice with the Florida PSC on July 18, 2014, but no adjustment to the factor was requested. Under recovered fuel costs at June 30, 2014 totaled $43.4 million and are included in under recovered regulatory clause revenues on Gulf Power's Condensed Balance Sheet herein. Fuel cost recovery revenues, as recorded on the financial statements, are adjusted

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for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, any changes in the billing factor would have no significant effect on Gulf Power's revenues or net income, but will affect cash flow.

Mississippi Power

Energy Efficiency

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

On June 3, 2014, the Mississippi PSC approved Mississippi Power's 2014 Energy Efficiency Quick Start Plan filing, which includes a portfolio of energy efficiency programs. On June 24, 2014, Mississippi Power submitted the 2014 Energy Efficiency Cost Recovery filing, which proposed an increase of $1.5 million in annual retail revenues to recover costs associated with energy efficiency programs. On July 21, 2014, the Mississippi PSC suspended the filing to allow more time for review.

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

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 18, 2014, Mississippi Power submitted its annual PEP lookback filing for 2013, which indicated no surcharge or refund. On March 31, 2014, the Mississippi PSC suspended the filing to allow more time for review.

On June 3, 2014, the Mississippi PSC issued an order for the purpose of investigating and reviewing the adoption of a uniform formula rate plan for Mississippi Power and other regulated electric utilities in Mississippi.

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

System Restoration Rider

See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – System Restoration Rider" in Item 8 of the Form 10-K for additional information.

On April 1, 2014, the Mississippi PSC approved Mississippi Power's request to continue a zero System Restoration Rider rate for 2014 and to accrue approximately $3.3 million to the property damage reserve in 2014.

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 a scrubber on Plant Daniel Units 1 and 2. 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. The project is scheduled for completion in December 2015. 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 June 30, 2014, total project expenditures were $419.6 million, of which Mississippi Power's portion was $213.7 million, excluding AFUDC of $13.3 million.

On August 1, 2014, Mississippi Power entered into a settlement agreement with the Sierra Club (Sierra Club Settlement Agreement) that, among other things, requires the Sierra Club to dismiss or withdraw all pending legal and regulatory challenges to the issuance of the CPCN to construct a scrubber on Plant Daniel Units 1 and 2. In addition, and consistent with Mississippi Power's ongoing evaluation of recent environmental rules and regulations, Mississippi Power agreed to retire, repower with natural gas, or convert to an alternative non-fossil fuel source Plant Sweatt Units 1 and 2 (80 MWs) no later than December 2018. Mississippi Power also agreed that it would cease

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burning coal and other solid fuel at Plant Watson Units 4 and 5 (750 MWs) and begin operating those units solely on natural gas no later than April 2015, and cease burning coal and other solid fuel at Plant Greene County Units 1 and 2 (200 MWs) and begin operating those units solely on natural gas no later than April 2016. On August 4, 2014, Mississippi Power, the Sierra Club, and the Mississippi PSC filed a joint motion to dismiss the appeal related to the CPCN to construct a scrubber on Plant Daniel Units 1 and 2.

In accordance with a 2011 accounting order from the Mississippi PSC, Mississippi Power has the authority to defer in a regulatory asset for future recovery all plant retirement- or partial retirement-related costs resulting from environmental regulations. Approved regulatory asset costs will be amortized over a period to be determined by the Mississippi PSC. As a result, these decisions are not expected to have a material impact on Southern Company's and Mississippi Power's financial statements. See "Other Matters – Sierra Club Settlement Agreement" herein for additional information.

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 June 30, 2014, the amount of under recovered retail fuel costs included on Mississippi Power's Condensed Balance Sheet herein was $14.5 million compared to over recovered retail fuel costs of $14.5 million at December 31, 2013.

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 May 6, 2014, the Mississippi PSC approved Mississippi Power's annual ad valorem tax adjustment factor filing for 2014, which requested an annual rate increase of 0.38%, or $3.6 million in annual retail revenues, primarily due to an increase in property tax rates.

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 Project Approval

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, which the Sierra Club appealed to the Chancery Court. Later in 2012, the Chancery Court affirmed the 2012 MPSC CPCN Order. In January 2013, the Sierra Club filed an appeal of the Chancery Court's ruling with the Mississippi Supreme Court.

On August 1, 2014, Mississippi Power entered into the Sierra Club Settlement Agreement that, among other things, requires the Sierra Club to dismiss or withdraw all pending legal and regulatory challenges against the Kemper IGCC, including the appeal to the Mississippi Supreme Court related to the 2012 MPSC CPCN. On August 4, 2014, Mississippi Power and the Sierra Club filed a joint motion to dismiss the appeal related to the 2012 MPSC CPCN. Also on August 4, 2014, Thomas A. Blanton, who is not a party to the CPCN appeal, filed a motion to stay the motion to dismiss. See "Other Matters – Sierra Club Settlement Agreement" herein for additional information.

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

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(UNAUDITED)

Kemper IGCC Schedule and Cost Estimate

The certificated cost estimate of the Kemper IGCC included in the 2012 MPSC CPCN Order was $2.4 billion, net of $245.3 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. Exceptions to the $2.88 billion cost cap include 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), as contemplated in the 2013 Settlement Agreement (defined below) and the 2012 MPSC CPCN Order. Recovery of the Cost Cap Exception amounts remains subject to review and approval by the Mississippi PSC.

The Kemper IGCC was originally scheduled to be placed in service in May 2014. Mississippi Power currently expects to place the combined cycle and the associated common facilities portion of the Kemper IGCC in service in the summer of 2014 and continues to focus on completing the remainder of the Kemper IGCC, including the gasification system, for which the in-service date is currently expected to occur in the second quarter 2015. On August 5, 2014, the Mississippi PSC ordered Mississippi Power to provide an analysis of the costs and benefits of placing the combined cycle and the associated common facilities portion of the Kemper IGCC in service in the summer of 2014 and to identify any expected or necessary accounting treatment and/or potential adjustments or impacts related to revenue recognition or any regulatory liability accounts.

Mississippi Power's 2010 project estimate, current cost estimate, and actual costs incurred as of June 30, 2014 for the Kemper IGCC are as follows:

Cost Category	2010 Project Estimate(e)		Current Estimate		Actual Costs at June 30, 2014
	(in billions)
Plant Subject to Cost Cap(a)	$	2.40	$	4.44	$	3.81
Lignite Mine and Equipment	0.21		0.24		0.23
CO2 Pipeline Facilities	0.14		0.11		0.10
AFUDC(b)(c)	0.17		0.55		0.37
General Exceptions	0.05		0.10		0.07
Regulatory Asset(c)(d)	—		0.12		0.09
Total Kemper IGCC(a)(c)	$	2.97	$	5.56	$	4.67

(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.

(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."

(c) Amounts in the Current Estimate reflect costs through May 31, 2015, but do not reflect any adjustments as a result of the expected placement of the combined cycle and the associated common facilities portion of the Kemper IGCC in service in the summer of 2014.

(d) 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."

(e) 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 incurred as of June 30, 2014, $3.01 billion was included in CWIP (which is net of the DOE Grants and estimated probable losses of $1.56 billion), $97.1 million in other regulatory assets, and $3.9 million in other deferred charges and assets in Southern Company's and Mississippi Power's Condensed Balance Sheets herein, and $1.1 million was previously expensed.

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(UNAUDITED)

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. Southern Company and Mississippi Power recorded pre-tax charges to income for revisions to the cost estimate of $380.0 million ($234.7 million after tax) in the first quarter 2014. This amount is in addition to charges totaling $1.18 billion ($728.7 million after tax) recognized through December 31, 2013. The first quarter 2014 revised cost estimate primarily reflects costs related to decreases in construction labor productivity at the Kemper IGCC identified in March 2014 due in large part to adverse weather, unexpected excessive craft labor turn-over, and unanticipated installation inefficiencies, as well as additional risk related to the expected in-service date as described herein. The revised cost estimate above includes costs through May 31, 2015. Any further extension of the in-service date is currently estimated to result in additional costs of approximately $20 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 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 performance, operational readiness, unforeseen engineering or design problems, start-up activities for this first-of-a-kind technology (including major equipment failure and system integration), and/or operations. 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 and Mississippi Power's statements of income 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 Seven-Year Rate Plan (described below) and other related proceedings during 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.

In 2012, the Mississippi PSC denied Mississippi Power's proposed rate schedule for recovery of financing costs during construction, pending a final ruling from the Mississippi Supreme Court regarding the Sierra Club's appeal of the Mississippi PSC's issuance of the CPCN for the Kemper IGCC (2012 MPSC CWIP Order). Mississippi Power appealed the Mississippi PSC's decision to the Mississippi Supreme Court and requested interim rates under bond. The Mississippi Supreme Court denied Mississippi Power's request for interim rates under bond.

2013 Settlement Agreement

In January 2013, Mississippi Power entered into a settlement agreement with the Mississippi PSC that, among other things, establishes the process for resolving matters regarding cost recovery related to the Kemper IGCC and dismissed Mississippi Power's appeal of the 2012 MPSC CWIP Order (2013 Settlement Agreement). Under the

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(UNAUDITED)

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 allows Mississippi Power to secure alternate financing for costs that are not otherwise recovered in any Mississippi PSC rate proceedings contemplated by the 2013 Settlement Agreement. 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 February 2013. Mississippi Power intends 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 as approved by the Mississippi PSC. The rate recovery necessary to recover the annual costs of securitization is expected to be filed and become effective following completion of the Mississippi PSC's prudence review of the costs to be securitized.

The 2013 Settlement Agreement provides that Mississippi Power may terminate the 2013 Settlement Agreement if certain conditions are not met, if Mississippi Power is unable to secure alternate financing for any prudently-incurred Kemper IGCC costs not otherwise recovered in any Mississippi PSC rate proceeding contemplated by the 2013 Settlement Agreement, or if the Mississippi PSC fails to comply with the requirements of the 2013 Settlement Agreement. Mississippi Power continues to work with the Mississippi PSC and the Mississippi Public Utilities Staff to implement the requirements of the 2013 Settlement Agreement.

2013 MPSC Rate Order

Consistent with the terms of the 2013 Settlement Agreement, in January 2013, Mississippi Power filed a new request to increase retail rates in 2013 by $172 million annually, based on projected investment for 2013.

In March 2013, the Mississippi PSC issued the 2013 MPSC Rate Order approving retail rate increases of 15% effective March 19, 2013, and 3% effective January 1, 2014, which collectively are designed to collect $156 million annually beginning in 2014. For year-to-date 2014, $74.3 million has been collected, with $11.1 million recognized in retail revenues in Southern Company's and Mississippi Power's Condensed Statements of Income herein and the remainder deferred in other regulatory liabilities to be used to mitigate customer rate impacts after the Kemper IGCC is placed in service and included in Southern Company's and Mississippi Power's Condensed Balance Sheets herein. Since March 2013, $172.4 million has been collected, with $21.3 million recognized in retail revenues in Southern Company's and Mississippi Power's Condensed Statements of Income herein, and the remainder deferred in other regulatory liabilities to be used to mitigate customer rate impacts after the Kemper IGCC is placed in service and included in Southern Company's and Mississippi Power's Condensed Balance Sheets herein.

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 during the construction period. 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 to comply with the 2013 MPSC Rate Order by collecting and deferring the approved rates during the construction period unless directed to do otherwise by the Mississippi PSC.

In March 2013, a legal challenge to the 2013 MPSC Rate Order was filed by Thomas A. Blanton with the Mississippi Supreme Court, which remains pending against Mississippi Power and the Mississippi PSC. On April 22, 2014, the Mississippi Supreme Court requested further briefing in this proceeding on a number of substantive issues relating to the 2013 MPSC Rate Order.

Seven-Year Rate Plan

In March 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 (Seven-Year Rate Plan), which is still under review by the Mississippi PSC. In the Seven-Year Rate 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

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(UNAUDITED)

MPSC Rate Order, which increased rates beginning in March 2013, is integral to the Seven-Year Rate 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 Seven-Year Rate 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 will review the amount and, if approved, determine the appropriate method and period of disposition.

The revenue requirements set forth in the Seven-Year Rate Plan assume the sale of a 15% undivided interest in the Kemper IGCC to SMEPA and utilization of bonus depreciation as provided by the American Taxpayer Relief Act of 2012 (ATRA), which currently requires that assets be placed in service in 2014. While Mississippi Power currently expects to place the combined cycle and the associated common facilities portion of the Kemper IGCC in service in the summer of 2014, extension of the in-service date for the remainder of the Kemper IGCC beyond 2014 results in the loss of tax benefits related to bonus depreciation under current law. The estimated value to retail customers of the bonus depreciation tax benefits not associated with the combined cycle and the associated common facilities portion of the Kemper IGCC is approximately $130 million to $160 million. See "Investment Tax Credits and Bonus Depreciation" herein for additional information regarding bonus depreciation.

Mississippi Power plans to further revise the Seven-Year Rate Plan to reflect changes including the revised in-service date, the change in expected benefits relating to tax credits, various other revenue requirement items, and other tax matters, including bonus depreciation, which include ensuring compliance with the normalization requirements of the Internal Revenue Code. The impact of these revisions for the average annual retail revenue requirement is estimated to be an increase of approximately $50 million through 2020. The revision of the Seven-Year Rate Plan is also expected to reflect rate mitigation options identified by Mississippi Power that, if approved by the Mississippi PSC, would result in no change to the total customer rate impacts contemplated in the original Seven-Year Rate Plan.

Any further cost increases and/or extensions of the in-service date with respect to the Kemper IGCC could have an adverse impact on the Seven-Year Rate Plan, including the inability to recover items considered as Cost Cap Exceptions.

In the event that the Mississippi PSC does not approve or Mississippi Power withdraws the Seven-Year Rate Plan, as ultimately revised, Mississippi Power would seek rate recovery through an alternate means, which could include a traditional rate case.

Prudence Reviews

The Mississippi PSC's review of Kemper IGCC costs is ongoing. On August 5, 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. 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.

Regulatory Assets

Consistent with the treatment of non-capital costs incurred during the pre-construction period, the Mississippi PSC granted Mississippi Power the authority to defer all non-capital Kemper IGCC-related costs to a regulatory asset during the construction period, subject to review of such costs by the Mississippi PSC. The amortization period of 40 years proposed by Mississippi Power for any such costs approved for recovery remains subject to approval by the Mississippi PSC. In addition, Mississippi Power is authorized to accrue carrying costs on the unamortized

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(UNAUDITED)

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.

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, a wholly-owned subsidiary of The North American Coal Corporation (Liberty Fuels), which will develop, construct, and manage 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 will acquire, construct, and 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.

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 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 asset purchase agreement 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 asset purchase agreement whereby Mississippi Power and SMEPA agreed to amend the power supply agreement entered into by the parties in April 2011 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 April 2011 power supply agreement were $17.5 million in 2013. In December 2013, Mississippi Power and SMEPA agreed to extend SMEPA's option to purchase through December 31, 2014. The sale and transfer of an interest in the Kemper IGCC to SMEPA are subject to approval by the Mississippi PSC.

The closing of this transaction is conditioned upon execution of a joint ownership and operating agreement, receipt of all construction permits, appropriate regulatory approvals, financing, and other conditions. In 2012, SMEPA received a conditional loan commitment from Rural Utilities Service to provide funding for SMEPA's undivided interest in the Kemper IGCC.

In 2012 and on January 2, 2014, Mississippi Power received $150 million and $75 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 asset purchase agreement or within 15 days of a request by SMEPA for a full or partial refund. Given the interest-bearing nature of the deposit and SMEPA's ability to request a refund, the deposits have been

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(UNAUDITED)

presented as a current liability in Southern Company's and Mississippi Power's Condensed Balance Sheets herein and as financing proceeds in Southern Company's and Mississippi Power's Condensed Statements of Cash Flows herein. In July 2013, Southern Company entered into an agreement with SMEPA under which Southern Company has agreed to guarantee the obligations of Mississippi Power with respect to any required refund of the deposits.

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

Baseload Act

In 2008, the Baseload Act was signed by the Governor of Mississippi. The Baseload Act authorizes, but does not require, the Mississippi PSC to adopt a cost recovery mechanism that includes in retail base rates, prior to and during construction, all or a portion of the prudently-incurred pre-construction and construction costs incurred by a utility in constructing a base load electric generating plant. Prior to the passage of the Baseload Act, such costs would traditionally be recovered only after the plant was placed in service. The Baseload Act also provides for periodic prudence reviews by the Mississippi PSC and prohibits the cancellation of any such generating plant without the approval of the Mississippi PSC. In the event of cancellation of the construction of the plant without approval of the Mississippi PSC, the Baseload Act authorizes the Mississippi PSC to make a public interest determination as to whether and to what extent the utility will be afforded rate recovery for costs incurred in connection with such cancelled generating plant. There are legal challenges to the constitutionality of the Baseload Act currently pending before the Mississippi Supreme Court. The ultimate outcome of any legal challenges to this legislation cannot be determined at this time. See "Rate Recovery of Kemper IGCC Costs" herein for additional information.

Investment Tax Credits and Bonus Depreciation

The IRS allocated $133 million (Phase I) and $279 million (Phase II) of Internal Revenue Code Section 48A tax credits to Mississippi Power in connection with the Kemper IGCC. In May 2013, the IRS notified Mississippi Power that no additional tax credits under the Internal Revenue Code Section 48A Phase III were allocated to the Kemper IGCC. As a result of the schedule extension for the Kemper IGCC, the Phase I credits have been recaptured. Through June 30, 2014, Mississippi Power had recorded tax benefits totaling $276.4 million for the remaining Phase II credits, which 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. A portion of the Phase II tax credits will be subject to recapture upon completion of SMEPA's purchase of an undivided interest in the Kemper IGCC as described above.

In January 2013, the ATRA was signed into law. The ATRA retroactively extended several tax credits through 2013 and extended 50% bonus depreciation for property placed in service in 2013 (and for certain long-term production-period projects to be placed in service in 2014), which is currently expected to apply primarily to the combined cycle and associated common facilities portion of the Kemper IGCC. The estimated cash flow benefit of approximately $120 million is dependent upon placing the assets in service in 2014. See "Rate Recovery of Kemper IGCC Costs – Seven-Year Rate Plan" herein for additional information.

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

Other Matters

Sierra Club Settlement Agreement

On August 1, 2014, Mississippi Power entered into the Sierra Club Settlement Agreement that, among other things, requires the Sierra Club to dismiss or withdraw all pending legal and regulatory challenges of the Kemper IGCC and the scrubber project at Plant Daniel Units 1 and 2. In addition, the Sierra Club agreed to refrain from initiating, intervening in, and/or challenging certain legal and regulatory proceedings for the Kemper IGCC, including, but not limited to, the prudence review, and Plant Daniel for a period of three years from the date of the Sierra Club

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(UNAUDITED)

Settlement Agreement. On August 4, 2014, the Sierra Club filed all of the required motions necessary to dismiss or withdraw.

Under the Sierra Club Settlement Agreement, Mississippi Power agreed to, among other things, fund a $15 million grant payable over a five-year period for an energy efficiency and renewable program and contribute $2 million to a conservation fund. In addition, and consistent with Mississippi Power's ongoing evaluation of recent environmental rules and regulations, Mississippi Power agreed to retire, repower with natural gas, or convert to an alternative non-fossil fuel source Plant Sweatt Units 1 and 2 (80 MWs) no later than December 2018. Mississippi Power also agreed that it would cease burning coal and other solid fuel at Plant Watson Units 4 and 5 (750 MWs) and begin operating those units solely on natural gas no later than April 2015, and cease burning coal and other solid fuel at Plant Greene County Units 1 and 2 (200 MWs) and begin operating those units solely on natural gas no later than April 2016. See "Retail Regulatory Matters – Mississippi Power – Environmental Compliance Overview Plan" herein for additional information.

(C) FAIR VALUE MEASUREMENTS

As of June 30, 2014, 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 June 30, 2014:	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	$	—	$	40	$	—	$	40
Nuclear decommissioning trusts(a)	651		877		2		1,530
Cash equivalents	321		—		—		321
Other investments	9		—		4		13
Total	$	981	$	917	$	6	$	1,904
Liabilities:
Energy-related derivatives	$	—	$	36	$	—	$	36
Alabama Power
Assets:
Energy-related derivatives	$	—	$	14	$	—	$	14
Nuclear decommissioning trusts(b)
Domestic equity	408		81		—		489
Foreign equity	36		68		—		104
U.S. Treasury and government agency securities	—		33		—		33
Corporate bonds	—		95		—		95
Mortgage and asset backed securities	—		20		—		20
Other	—		5		2		7
Total	$	444	$	316	$	2	$	762
Liabilities:
Energy-related derivatives	$	—	$	5	$	—	$	5

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(UNAUDITED)

	Fair Value Measurements Using
As of June 30, 2014:	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	$	—	$	7	$	—	$	7
Nuclear decommissioning trusts(b) (c)
Domestic equity	194		1		—		195
Foreign equity	—		138		—		138
U.S. Treasury and government agency securities	—		132		—		132
Municipal bonds	—		34		—		34
Corporate bonds	—		157		—		157
Mortgage and asset backed securities	—		108		—		108
Other	13		5		—		18
Total	$	207	$	582	$	—	$	789
Liabilities:
Energy-related derivatives	$	—	$	15	$	—	$	15
Gulf Power
Assets:
Energy-related derivatives	$	—	$	12	$	—	$	12
Cash equivalents	18		—		—		18
Total	$	18	$	12	$	—	$	30
Liabilities:
Energy-related derivatives	$	—	$	11	$	—	$	11
Mississippi Power
Assets:
Energy-related derivatives	$	—	$	7	$	—	$	7
Cash equivalents	205		—		—		205
Total	$	205	$	7	$	—	$	212
Liabilities:
Energy-related derivatives	$	—	$	5	$	—	$	5
Southern Power
Assets:
Cash equivalents	$	17	$	—	$	—	$	17
Total	$	17	$	—	$	—	$	17

(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, and payables related to pending investment purchases.

(c) Includes the investment securities pledged to creditors and cash collateral received and excludes payables related to the securities lending program. As of June 30, 2014, approximately $49 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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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 and foreign currency 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. Inputs for foreign currency derivatives are from observable market sources. See Note (H) herein for additional information on how these derivatives are used.

For fair value measurements of investments within the nuclear decommissioning trusts, specifically the fixed income assets using significant other observable inputs and unobservable inputs, the primary valuation technique used is the market approach. External pricing vendors are designated for each of the asset classes in the nuclear decommissioning trusts with each security discriminately assigned a primary pricing source, based on similar characteristics. 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, 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 the 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 in funds that are valued using the market approach and income approach. Securities that are traded in the open market are valued at the closing price on their principal exchange as of the measurement date. Discounts are applied in accordance with GAAP when certain trading restrictions exist. For investments that are not traded in the open market, the price paid will have been determined based on market factors including comparable multiples and the expectations regarding cash flows and business plan execution. As the investments mature or if market conditions change materially, further analysis of the fair market value of the investment is performed. This analysis is typically based on a metric, such as multiple of earnings, revenues, earnings before interest and income taxes, or earnings adjusted for certain cash changes. These multiples are based on comparable multiples for publicly traded companies or other relevant prior transactions.

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As of June 30, 2014, 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 June 30, 2014:	Fair Value		Unfunded Commitments	Redemption Frequency	Redemption Notice Period
	(in millions)
Southern Company
Nuclear decommissioning trusts:
Foreign equity funds	$	138	None	Monthly	5 days
Equity - commingled funds	68		None	Daily/Monthly	Daily/7 days
Other - commingled funds	5		None	Daily	Not applicable
Other - money market funds	13		None	Daily	Not applicable
Trust-owned life insurance	114		None	Daily	15 days
Cash equivalents:
Money market funds	321		None	Daily	Not applicable
Alabama Power
Nuclear decommissioning trusts:
Equity - commingled funds	$	68	None	Daily/Monthly	Daily/7 days
Trust-owned life insurance	114		None	Daily	15 days
Georgia Power
Nuclear decommissioning trusts:
Foreign equity funds	$	138	None	Monthly	5 days
Other - commingled funds	5		None	Daily	Not applicable
Other - money market funds	13		None	Daily	Not applicable
Gulf Power
Cash equivalents:
Money market funds	$	18	None	Daily	Not applicable
Mississippi Power
Cash equivalents:
Money market funds	$	205	None	Daily	Not applicable
Southern Power
Cash equivalents:
Money market funds	$	17	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 commingled funds in Georgia Power's nuclear decommissioning trusts are invested primarily in a diversified portfolio, including, but not limited to, commercial paper, notes, repurchase agreements, and other evidences of

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(UNAUDITED)

indebtedness with a maturity not exceeding 13 months from the date of purchase. The commingled funds will, however, generally maintain a dollar-weighted average portfolio maturity of 90 days or less. The assets may be longer term investment grade fixed income obligations with maturity shortening provisions. The primary objective for the commingled funds is a high level of current income consistent with stability of principal and liquidity. Included in commingled funds as of June 30, 2014 is $5 million representing the investment of cash collateral received under the Funds' managers' securities lending program that can only be sold upon the return of the loaned securities. The money market fund within Georgia Power's nuclear decommissioning trusts represents the short-term investment of the trusts' excess cash with the goal of providing the highest possible level of income while preserving capital and maintaining liquidity. The fund's positions are in high-quality, short-term, liquid money market instruments including, but not limited to, commercial paper, floating and variable rate demand notes, debt securities issued or guaranteed by the U.S. government and its agencies, time deposits, repurchase agreements, municipal obligations, and other high-quality, short-term debt securities. The fund maintains a dollar-weighted average maturity of 60 days or less and is regulated by, and subject to, the money market regulatory requirements set by the SEC. 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 trust includes investments in Trust-Owned Life Insurance (TOLI). The taxable nuclear decommissioning trust invests in the TOLI in order to minimize the impact of taxes on the portfolio 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 trust does 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. The commingled funds 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, to some degree, 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 and six months ended June 30, 2014, the change in fair value of the funds, including reinvested interest and dividends reduced by the funds' expenses, increased by $56 million and $83 million, respectively, at Southern Company. Alabama Power recorded an increase in fair value of $31 million and $47 million, respectively, as an increase in regulatory liabilities. Georgia Power recorded an increase in fair value of $25 million and $36 million, respectively, as a reduction of its regulatory asset related to its asset retirement obligations.

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.

154

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(UNAUDITED)

As of June 30, 2014, 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	$	22,542	$	23,883
Alabama Power	$	6,229	$	6,800
Georgia Power	$	9,557	$	10,112
Gulf Power	$	1,246	$	1,306
Mississippi Power	$	2,577	$	2,571
Southern Power	$	1,629	$	1,752

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 effects of both stock options and performance share award units were determined using the treasury stock method. Shares used to compute diluted earnings per share were as follows:

	Three Months Ended June 30, 2014	Three Months Ended June 30, 2013	Six Months Ended June 30, 2014	Six Months Ended June 30, 2013
	(in millions)
As reported shares	895	874	892	872
Effect of options and performance share award units	4	5	4	5
Diluted shares	899	879	896	877

Stock options and performance share award units that were not included in the diluted earnings per share calculation because they were anti-dilutive were 8 million and 17 million for the three and six months ended June 30, 2014, respectively, and were immaterial for the three and six months ended June 30, 2013.

155

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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
	(in thousands)						(in millions)
Balance at December 31, 2013	892,733	(5,647	)	$	19,008		$	756	$	19,764
Net income after dividends on preferred and preference stock	—	—		962			—		962
Other comprehensive income (loss)	—	—		4			—		4
Treasury stock re-issued	—	4,739		216			—		216
Stock issued	3,898	—		161			—		161
Stock repurchased, at cost	—	—		(5		)	—		(5		)
Cash dividends on common stock	—	—		(920		)	—		(920		)
Other	—	(27	)	—			—		—
Balance at June 30, 2014	896,631	(935	)	$	19,426		$	756	$	20,182
Balance at December 31, 2012	877,803	(10,035	)	$	18,297		$	707	$	19,004
Net income after dividends on preferred and preference stock	—	—		378			—		378
Other comprehensive income (loss)	—	—		9			—		9
Stock issued	6,144	—		244			49		293
Stock repurchased, at cost	—	—		(18		)	—		(18		)
Cash dividends on common stock	—	—		(870		)	—		(870		)
Other	—	(9	)	—			—		—
Balance at June 30, 2013	883,947	(10,044	)	$	18,040		$	756	$	18,796

156

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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 requiring liquidity support as of June 30, 2014 was approximately $1.7 billion. In addition, at June 30, 2014, the traditional operating companies had $495 million of fixed rate pollution control revenue bonds that will be 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.

The following table outlines the committed credit arrangements by company as of June 30, 2014:

	Expires														Executable Term Loans				Due Within One Year
Company	2014		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	163		110		—		—		1,030		1,303		1,303		53		—		53		185
Georgia Power	—		—		150		—		1,600		1,750		1,736		—		—		—		—
Gulf Power	20		60		165		30		—		275		275		50		—		50		30
Mississippi Power	40		95		165		—		—		300		300		25		40		65		70
Southern Power	—		—		—		—		500		500		499		—		—		—		—
Other	—		70		—		—		—		70		70		20		—		20		25
Total	$	223	$	335	$	480	$	30	$	4,130	$	5,198	$	5,183	$	148	$	40	$	188	$	310

Southern Company and its subsidiaries expect to renew their credit arrangements as needed, prior to expiration.

157

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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 six months of 2014:

Company(a)	Senior Note Maturities		Revenue Bond Issuances and Remarketings of Purchased Bonds(b)		Revenue Bond Redemptions		Other Long-Term Debt Issuances			Other Long-Term Debt Redemptions(c)
	(in millions)
Southern Company	$	350	$	—	$	—	$	—		$	—
Georgia Power	—		—		37		1,000			3
Gulf Power	—		42		29		—			—
Mississippi Power	—		—		—		482			1
Southern Power	—		—		—		10			1
Other	—		—		—		—			10
Elimination(d)	—		—		—		(220		)	—
Total	$	350	$	42	$	66	$	1,272		$	15

(a) Alabama Power did not issue or redeem any long-term debt during the first six months of 2014.

(b) Includes remarketing by Gulf Power of $13 million aggregate principal amount of revenue bonds previously purchased and held by Gulf Power since December 2013.

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

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

Georgia Power

Pursuant to the loan guarantee program established under Title XVII of the Energy Policy Act of 2005, Georgia Power and the DOE entered into a loan guarantee agreement (Loan Guarantee Agreement) on February 20, 2014, under which the DOE agreed to guarantee the obligations of Georgia Power under a note purchase agreement (FFB Note Purchase Agreement) among the DOE, Georgia Power, and the FFB and a related promissory note (FFB Promissory Note). Georgia Power is obligated to reimburse the DOE for any payments the DOE is required to make to the FFB under the guarantee.

The FFB Note Purchase Agreement and the FFB Promissory Note provide for a multi-advance term loan facility (FFB Credit Facility), under which Georgia Power may make term loan borrowings through the FFB. On February 20, 2014, Georgia Power made initial borrowings under the FFB Credit Facility in an aggregate principal amount of $1.0 billion. Georgia Power's reimbursement obligations to the DOE are secured by a first priority lien on (i) Georgia Power's 45.7% undivided ownership interest in Plant Vogtle Units 3 and 4 (primarily the units under construction, the related real property, and any nuclear fuel loaded in the reactor core) and (ii) Georgia Power's rights and obligations under the principal contracts relating to Plant Vogtle Units 3 and 4. The interest rate applicable to $500 million of the initial advance under the FFB Credit Facility is 3.860% for an interest period that extends to February 20, 2044 (the final maturity date) and the interest rate applicable to the remaining $500 million is 3.488% for an interest period that extends to February 20, 2029, and is expected to be reset from time to time thereafter through the final maturity date. In connection with its entry into the Loan Guarantee Agreement, the FFB Note Purchase Agreement, and the FFB Promissory Note, Georgia Power incurred issuance costs of approximately $66 million, which will be amortized over the life of the borrowings under the FFB Credit Facility.

See Note 6 to the financial statements of Southern Company and Georgia Power in Item 8 of the Form 10-K under "DOE Loan Guarantee Borrowings" for additional information.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Gulf Power

In April 2014, Gulf Power executed a loan agreement with Mississippi Business Finance Corporation (MBFC) related to MBFC's issuance of $29.075 million aggregate principal amount of Pollution Control Revenue Refunding Bonds, First Series 2014 (Gulf Power Company Project) due April 1, 2044 for the benefit of Gulf Power. The proceeds were used to redeem $29.075 million aggregate principal amount of MBFC Pollution Control Revenue Refunding Bonds, Series 2003 (Gulf Power Company Project).

In June 2014, Gulf Power reoffered to the public $13 million aggregate principal amount of MBFC Solid Waste Disposal Facilities Revenue Refunding Bonds, Series 2012 (Gulf Power Company Project), which had been previously purchased and held by Gulf Power since December 2013.

Mississippi Power

In January 2014, Mississippi Power entered into an 18-month floating rate bank loan bearing interest based on one-month LIBOR. This term loan was for $250 million aggregate principal amount, and proceeds were used for working capital and other general corporate purposes, including Mississippi Power's continuous construction program.

In January 2014, Mississippi Power received an additional $75 million interest-bearing refundable deposit from SMEPA to be applied to the sale price for the pending sale of an undivided interest in the Kemper IGCC. See Note 3 to the financial statements of Southern Company and Mississippi Power in Item 8 of the Form 10-K under "Integrated Coal Gasification Combined Cycle – Proposed Sale of Undivided Interest to SMEPA" for additional information.

As reflected in the table above in "Other Long-Term Debt Issuances," in May 2014, Mississippi Power issued a 19-month floating rate promissory note to Southern Company for a loan bearing interest based on one-month LIBOR. This loan was for $220 million aggregate principal amount and the proceeds were used for working capital and other general corporate purposes, including Mississippi Power's construction program.

Also in May 2014, the MBFC issued $12.3 million aggregate principal amount of MBFC Taxable Revenue Bonds (Mississippi Power Company Project), Series 2013A for the benefit of Mississippi Power and proceeds were used to reimburse Mississippi Power for the cost of the acquisition, construction, equipping, installation, and improvement of certain equipment and facilities for the lignite mining facility related to the Kemper IGCC. Any future issuances of the Series 2013A bonds will be used for this same purpose.

Southern Power

During the six months ended June 30, 2014, Southern Power prepaid $0.8 million of long-term debt to TRE and issued $3.8 million due April 30, 2034, $5.3 million due May 31, 2034, and an additional $0.8 million due April 30, 2033 under promissory notes payable to TRE related to the financing of Adobe, Macho Springs, and Campo Verde Solar, LLC, respectively.

(F) RETIREMENT BENEFITS

Southern Company has a defined benefit, trusteed, pension plan covering substantially all employees. The qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended. No mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2014. 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.

159

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Components of the net periodic benefit costs for the three and six months ended June 30, 2014 and 2013 were as follows:

Pension Plans	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power
	(in millions)
Three Months Ended June 30, 2014
Service cost	$	54		$	12		$	15		$	1		$	2
Interest cost	108			26			38			5			5
Expected return on plan assets	(162		)	(42		)	(56		)	(7		)	(7		)
Amortization:
Prior service costs	7			2			2			1			1
Net (gain)/loss	27			8			10			1			1
Net cost	$	34		$	6		$	9		$	1		$	2
Six Months Ended June 30, 2014
Service cost	$	107		$	24		$	31		$	4		$	5
Interest cost	217			52			76			10			10
Expected return on plan assets	(323		)	(84		)	(113		)	(14		)	(14		)
Amortization:
Prior service costs	13			3			5			1			1
Net (gain)/loss	55			16			20			2			2
Net cost	$	69		$	11		$	19		$	3		$	4
Three Months Ended June 30, 2013
Service cost	$	58		$	14		$	18		$	2		$	2
Interest cost	97			23			35			5			4
Expected return on plan assets	(150		)	(39		)	(53		)	(7		)	(6		)
Amortization:
Prior service costs	6			1			2			1			—
Net (gain)/loss	50			13			18			2			3
Net cost	$	61		$	12		$	20		$	3		$	3
Six Months Ended June 30, 2013
Service cost	$	116		$	27		$	35		$	5		$	5
Interest cost	194			46			69			9			9
Expected return on plan assets	(301		)	(78		)	(106		)	(13		)	(13		)
Amortization:
Prior service costs	13			3			5			1			—
Net (gain)/loss	100			26			37			4			5
Net cost	$	122		$	24		$	40		$	6		$	6

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(UNAUDITED)

Postretirement Benefits	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power
	(in millions)
Three Months Ended June 30, 2014
Service cost	$	6		$	2		$	1		$	1		$	1
Interest cost	20			5			9			1			1
Expected return on plan assets	(15		)	(7		)	(7		)	(1		)	(1		)
Amortization:
Prior service costs	1			1			—			—			—
Net (gain)/loss	—			—			1			—			—
Net cost	$	12		$	1		$	4		$	1		$	1
Six Months Ended June 30, 2014
Service cost	$	11		$	3		$	3		$	1		$	1
Interest cost	40			10			17			2			2
Expected return on plan assets	(30		)	(13		)	(13		)	(1		)	(1		)
Amortization:
Prior service costs	2			2			—			—			—
Net (gain)/loss	1			—			1			—			—
Net cost	$	24		$	2		$	8		$	2		$	2
Three Months Ended June 30, 2013
Service cost	$	6		$	1		$	1		$	1		$	1
Interest cost	18			4			8			—			1
Expected return on plan assets	(14		)	(6		)	(6		)	—			(1		)
Amortization:
Transition obligation	1			—			1			—			—
Prior service costs	1			1			—			—			—
Net (gain)/loss	3			1			2			—			—
Net cost	$	15		$	1		$	6		$	1		$	1
Six Months Ended June 30, 2013
Service cost	$	12		$	3		$	3		$	1		$	1
Interest cost	37			9			16			1			2
Expected return on plan assets	(28		)	(12		)	(12		)	—			(1		)
Amortization:
Transition obligation	2			—			2			—			—
Prior service costs	2			2			—			—			—
Net (gain)/loss	6			1			4			—			—
Net cost	$	31		$	3		$	13		$	2		$	2

161

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(UNAUDITED)

(G) 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 33.3% for the six months ended June 30, 2014 compared to 31.4% for the corresponding period in 2013. The increase was primarily due to higher net income, which was partially offset by an increase in non-taxable AFUDC equity, changes in state apportionment, and beneficial changes in certain state income tax laws.

Alabama Power

Alabama Power's effective tax rate was 39.3% for the six months ended June 30, 2014 compared to 39.2% for the corresponding period in 2013.

Georgia Power

Georgia Power's effective tax rate was 37.0% for the six months ended June 30, 2014 compared to 38.2% for the corresponding period in 2013. The decrease was primarily due to recognition in the second quarter 2014 of tax benefits related to emission allowances and state apportionment.

Gulf Power

Gulf Power's effective tax rate was 37.3% for the six months ended June 30, 2014 compared to 37.7% for the corresponding period in 2013.

Mississippi Power

Mississippi Power's effective tax rate was (51.1)% for the six months ended June 30, 2014 compared to (41.0)% for the corresponding period in 2013. The change in the tax benefit was primarily due to a reduced net loss for the current period compared to the corresponding period in 2013 and an increase in non-taxable AFUDC equity related to the construction of the Kemper IGCC.

Southern Power

Southern Power's effective tax rate was 0.3% for the six months ended June 30, 2014 compared to 25.1% for the corresponding period in 2013. The decrease was primarily due to the impact of state apportionment changes which reduced Southern Power's deferred tax liabilities, a change in filing method for North Carolina income tax, an increase in state income tax credits, and beneficial changes in certain state income tax laws.

(H) DERIVATIVES

Southern Company, the traditional operating companies, and Southern Power are exposed to market risks, primarily commodity price risk, interest rate risk, and occasionally foreign currency risk. To manage the volatility attributable to these exposures, each company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to each company's policies in areas such as counterparty exposure and risk management practices. Each company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a gross basis. In the statements of cash flows, the cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities and the cash impacts of settled foreign currency derivatives are recorded as investing activities.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

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, Southern Power has been and may continue to be exposed to market volatility in energy-related commodity prices as a result of sales from its uncontracted generating capacity. Further, the traditional operating companies may be exposed to market volatility in energy-related commodity prices to the extent any uncontracted wholesale generating capacity is used to sell electricity. Gulf Power currently has long-term sales agreements for 100% of its wholesale capacity through 2015 and 57% through 2018.

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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(UNAUDITED)

At June 30, 2014, the net volume of energy-related derivative contracts for natural gas positions for the Southern Company system, together with the longest hedge date over which the respective entity is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest non-hedge date for derivatives not designated as hedges, were as follows:

	Net Purchased mmBtu	Longest Hedge Date	Longest Non-Hedge Date
	(in millions)
Southern Company	250	2018	2017
Alabama Power	63	2017	—
Georgia Power	50	2017	—
Gulf Power	85	2018	—
Mississippi Power	51	2017	—
Southern Power	1	—	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 8 million mmBtu for Southern Company, 1 million mmBtu for Alabama Power, 5 million mmBtu for Georgia Power, 1 million mmBtu for Gulf 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 June 30, 2015 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 June 30, 2014, the following interest rate derivatives were outstanding:

	Notional Amount		Interest Rate Received	Weighted Average Interest Rate Paid	Hedge Maturity Date	Fair Value Gain (Loss) June 30, 2014
	(in millions)					(in millions)
Cash flow hedges of forecasted debt
Alabama Power	$	75	3-month LIBOR	3.12%	October 2025	$	—

The estimated pre-tax gains (losses) that will be reclassified from accumulated OCI to interest expense for the next 12-month period ending June 30, 2015 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.

Foreign Currency Derivatives

Southern Company and certain subsidiaries may enter into foreign currency derivatives to hedge exposure to changes in foreign currency exchange rates arising from purchases of equipment denominated in a currency other

164

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

than U.S. dollars. Derivatives related to a firm commitment in a foreign currency transaction are accounted for as fair value hedges where the derivatives' fair value gains or losses and the hedged items' fair value gains or losses are both recorded directly to earnings. Derivatives related to a forecasted transaction 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. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. Any ineffectiveness is recorded directly to earnings; however, Mississippi Power has regulatory approval allowing it to defer any ineffectiveness associated with firm commitments related to the Kemper IGCC to a regulatory asset.

At June 30, 2014, there were no foreign currency derivatives outstanding.

Derivative Financial Statement Presentation and Amounts

At June 30, 2014, the fair value of energy-related derivatives was reflected in the balance sheets as follows:

Asset Derivatives at June 30, 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	$	31	$	12	$	6	$	8	$	5
Other deferred charges and assets	9		2		1		4		2
Total asset derivatives	$	40	$	14	$	7	$	12	$	7	N/A

Liability Derivatives at June 30, 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:
Liabilities from risk management activities	$	19	$	2	$	11	$	4	$	2
Other deferred credits and liabilities	17		3		4		7		3
Total liability derivatives	$	36	$	5	$	15	$	11	$	5	N/A

165

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

At December 31, 2013, the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows:

Asset Derivatives at December 31, 2013
	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	$	16	$	5	$	3	$	5	$	3
Other deferred charges and assets	7		2		2		2		2
Total derivatives designated as hedging instruments for regulatory purposes	$	23	$	7	$	5	$	7	$	5	N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current assets	3		—		—		—		—		$	—
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other deferred charges and assets	1		—		—		—		—		1
Total asset derivatives	$	27	$	7	$	5	$	7	$	5	$	1

Liability Derivatives at December 31, 2013
	Fair Value
Derivative Category and Balance Sheet Location	Southern Company		Alabama Power		Georgia Power		Gulf Power		Mississippi Power		Southern Power
	(in millions)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Liabilities from risk management activities	$	26	$	3	$	13	$	6	$	4
Other deferred credits and liabilities	29		5		8		11		6
Total derivatives designated as hedging instruments for regulatory purposes	$	55	$	8	$	21	$	17	$	10	N/A
Derivatives not designated as hedging instruments
Energy-related derivatives:
Liabilities from risk management activities	1		—		—		—		—		$	1
Total liability derivatives	$	56	$	8	$	21	$	17	$	10	$	1

All derivative instruments are measured at fair value. See Note (C) herein for additional information.

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 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 at June 30, 2014 and December 31,

166

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

2013 are presented in the following tables. Interest rate derivatives presented in the tables above do not have amounts available for offset and are therefore excluded from the offsetting disclosure tables below.

Derivative Contracts at June 30, 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)	$	40		$	14		$	7		$	12		$	7		$	—
Gross amounts not offset in the Balance Sheet (b)	(30		)	(5		)	(7		)	(8		)	(4		)	—
Net energy-related derivative assets	$	10		$	9		$	—		$	4		$	3		$	—
Liabilities
Energy-related derivatives:
Energy-related derivatives presented in the Balance Sheet (a)	$	36		$	5		$	15		$	11		$	5		$	—
Gross amounts not offset in the Balance Sheet (b)	(30		)	(5		)	(7		)	(8		)	(4		)	—
Net energy-related derivative liabilities	$	6		$	—		$	8		$	3		$	1		$	—

(a) None of the registrants offset 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, 2013
	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)	$	24		$	7		$	5		$	7		$	5		$	1
Gross amounts not offset in the Balance Sheet (b)	(22		)	(5		)	(5		)	(6		)	(4		)	—
Net energy-related derivative assets	$	2		$	2		$	—		$	1		$	1		$	1
Liabilities
Energy-related derivatives:
Energy-related derivatives presented in the Balance Sheet (a)	$	56		$	8		$	21		$	17		$	10		$	1
Gross amounts not offset in the Balance Sheet (b)	(22		)	(5		)	(5		)	(6		)	(4		)	—
Net energy-related derivative liabilities	$	34		$	3		$	16		$	11		$	6		$	1

(a) None of the registrants offset 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.

167

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

At June 30, 2014 and December 31, 2013, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred on the balance sheets were as follows:

Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet at June 30, 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	$	(19	)	$	(2	)	$	(11	)	$	(4	)	$	(2	)
Other regulatory assets, deferred	(17		)	(3		)	(4		)	(7		)	(3		)
Other regulatory liabilities, current	31			12			6			8			5
Other regulatory liabilities, deferred	9			2			1			4			2
Total energy-related derivative gains (losses)	$	4		$	9		$	(8	)	$	1		$	2

Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet at December 31, 2013
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	$	(26	)	$	(3	)	$	(13	)	$	(6	)	$	(4	)
Other regulatory assets, deferred	(29		)	(5		)	(8		)	(11		)	(6		)
Other regulatory liabilities, current	16			5			3			5			3
Other regulatory liabilities, deferred (a)	7			2			2			2			2
Total energy-related derivative gains (losses)	$	(32	)	$	(1	)	$	(16	)	$	(10	)	$	(5	)

(a) Georgia Power includes Other regulatory liabilities, deferred in Other deferred credits and liabilities.

For the three and six months ended June 30, 2014 and 2013, the pre-tax effects of interest rate and foreign currency derivatives designated as fair value hedging instruments on the statements of income were immaterial on a gross basis for all registrants. Furthermore, the pre-tax effects of interest rate derivatives designated as fair value instruments on the statements of income were offset by changes to the carrying value of long-term debt and the pre-tax effects of foreign currency derivatives designated as fair value hedging instruments on the statements of income were offset by changes in the fair value of the purchase commitment related to equipment purchases.

For the three and six months ended June 30, 2014 and 2013, the pre-tax effects of energy-related derivatives and interest rate derivatives designated as cash flow hedging instruments recognized in OCI and those reclassified from accumulated OCI into earnings were immaterial for all registrants.

There was no material ineffectiveness recorded in earnings for any registrant for any period presented.

For the three and six months ended June 30, 2014 and 2013, the pre-tax effects of energy-related and foreign currency derivatives not designated as hedging instruments on the statements of income were immaterial for all registrants.

For Southern Power's energy-related derivatives not designated as hedging instruments, a portion of the pre-tax realized and unrealized gains and losses was associated with hedging fuel price risk of certain PPA customers and had no impact on net income or on fuel expense as presented in Southern Company's and Southern Power's statements of income for the three and six months ended June 30, 2014 and 2013. This third party hedging activity has been discontinued.

168

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Contingent Features

The registrants do not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain Southern Company subsidiaries. At June 30, 2014, the registrants' collateral posted with their derivative counterparties was immaterial.

At June 30, 2014, the fair value of derivative liabilities with contingent features was immaterial for all registrants. The maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, were immaterial 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

Adobe Solar, LLC

See Note 2 to the financial statements of Southern Power under "Adobe Solar, LLC" in Item 8 of the Form 10-K for additional information.

On April 17, 2014, Southern Power and TRE, through Southern Turner Renewable Energy, LLC (STR), a jointly-owned subsidiary owned 90% by Southern Power, acquired all of the outstanding membership interests of Adobe Solar, LLC (Adobe) from Sun Edison, LLC, the original developer of the project. Adobe constructed and owns an approximately 20-MW solar photovoltaic facility in Kern County, California. The solar facility began commercial operation on May 21, 2014 and has the entire output of the plant contracted under a 20-year PPA with Southern California Edison Company. The acquisition is in accordance with Southern Power's overall growth strategy.

Southern Power's acquisition of Adobe included cash consideration of approximately $90.5 million. The outstanding balance of $4.7 million remains to be paid upon completion of certain milestones. As of June 30, 2014, the purchase price was recorded primarily as property, plant, and equipment with $13.4 million recorded in receivables reflecting reimbursable transmission costs; however, the allocation of the purchase price to individual assets has not been finalized. The acquisition did not include any contingent consideration. Acquisition-related costs were expensed as incurred and were not material.

Macho Springs Solar, LLC

On May 22, 2014, Southern Power and TRE, through STR, acquired all of the outstanding membership interests ofMacho Springs Solar, LLC (Macho Springs) from First Solar Development, LLC, the original developer of the project. Macho Springs constructed and owns an approximately50-MW solar photovoltaic facility in Luna County, New Mexico. The solar facility began commercial operation on May 23,2014and has the entire output of the plant contracted under a20-year PPA withEl Paso Electric Company. The acquisition is in accordance with Southern Power's overall growth strategy.

169

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Southern Power's acquisition of Macho Springs included cash consideration of approximately $130.0 million. As of June 30, 2014, the purchase price was recorded primarily as property, plant, and equipment; however, the allocation of the purchase price to individual assets has not been finalized. The acquisition did not include any contingent consideration. Acquisition-related costs were expensed as incurred and were not material.

(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 $68 million and $140 million for the three and six months ended June 30, 2014, respectively, and $89 million and $167 million for the three and six months ended June 30, 2013, 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 and six months ended June 30, 2014 and 2013 was as follows:

	Electric Utilities
	Traditional Operating Companies		Southern Power		Eliminations			Total		All Other			Eliminations			Consolidated
	(in millions)
Three Months Ended June 30, 2014:
Operating revenues	$	4,209	$	329	$	(84	)	$	4,454	$	39		$	(26	)	$	4,467
Segment net income (loss)(a)	580		31		—			611		2			(2		)	611
Six Months Ended June 30, 2014:
Operating revenues	$	8,587	$	680	$	(186	)	$	9,081	$	80		$	(50	)	$	9,111
Segment net income (loss)(a)(c)	899		64		—			963		2			(3		)	962
Total assets at June 30, 2014	$	61,210	$	4,605	$	(132	)	$	65,683	$	1,356		$	(639	)	$	66,400
Three Months Ended June 30, 2013:
Operating revenues	$	4,018	$	307	$	(95	)	$	4,230	$	38		$	(22	)	$	4,246
Segment net income (loss)(a)(b)	268		28		—			296		4			(3		)	297
Six Months Ended June 30, 2013:
Operating revenues	$	7,687	$	610	$	(181	)	$	8,116	$	73		$	(46	)	$	8,143
Segment net income (loss)(a)(c)	334		57		—			391		(12		)	(1		)	378
Total assets at December 31, 2013	$	59,447	$	4,429	$	(101	)	$	63,775	$	1,077		$	(306	)	$	64,546

(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 June 30, 2013 includes a $450.0 million pre-tax charge ($277.9 million after tax) for an estimated probable loss on the Kemper IGCC. See Note (B) under "Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" herein for additional information.

(c) Segment net income (loss) for the traditional operating companies for the six months ended June 30, 2014 and June 30, 2013 includes $380.0 million in pre-tax charges ($234.7 million after tax) and $990.0 million in pre-tax charges ($611.3 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.

170

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Products and Services

	Electric Utilities' Revenues
Period	Retail		Wholesale		Other		Total
	(in millions)
Three Months Ended June 30, 2014	$	3,770	$	515	$	169	$	4,454
Three Months Ended June 30, 2013	3,620		454		156		4,230
Six Months Ended June 30, 2014	$	7,628	$	1,119	$	334	$	9,081
Six Months Ended June 30, 2013	6,918		886		312		8,116

171

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 6.    Exhibits.

The exhibits marked with a pound sign (#) are management contracts or compensatory plans or arrangements required to be identified as such by Item 6 of Form 10-Q.

	(10) Material Contracts
	Gulf Power
#	(d)1	-	Separation and Release Agreement between P. Bernard Jacob and Gulf Power effective May 2, 2014.
	(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, 2013, File No. 1-3526 as Exhibit 24(a) and incorporated herein by reference.)
	Alabama Power
	(b)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2013, File No. 1-3164 as Exhibit 24(b) and incorporated herein by reference.)
	(b)2	-	Power of Attorney for Mark A. Crosswhite. (Designated in the Form 10-Q for the quarter ended March 31, 2014, File No. 1-3164 as Exhibit 24(b)2 and incorporated herein by reference.)
	Georgia Power
	(c)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2013, File No. 1-6468 as Exhibit 24(c) and incorporated herein by reference.)
	Gulf Power
	(d)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2013, File No. 001-31737 as Exhibit 24(d)(1) and incorporated herein by reference.)
	Mississippi Power
	(e)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2013, File No. 001-11229 as Exhibit 24(e) and incorporated herein by reference.)

172

Southern Power
(f)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2013, File No. 333-98553 as Exhibit 24(f) and incorporated herein by reference.)
(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's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
(f)2	-	Certificate of Southern Power's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
(32) Section 906 Certifications
Southern Company
(a)	-	Certificate of Southern Company's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.

173

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'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

174

THE SOUTHERN COMPANY

SIGNATURES

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

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

Date: August 7, 2014

175

ALABAMA POWER COMPANY

SIGNATURES

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

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

Date: August 7, 2014

176

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: August 7, 2014

177

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: August 7, 2014

178

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: August 7, 2014

179

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: August 7, 2014

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EX-10.D1

Exhibit 10(d)1

SEPARATION AND RELEASE AGREEMENT

This SEPARATION AND RELEASE AGREEMENT (Agreement) is entered into by PAUL BERNARD JACOB (Employee) and GULF POWER COMPANY (Company) and arises out of Employee’s separation from service. In consideration of the material promises contained herein, the parties agree as follows:

1. SEPARATION FROM SERVICE.

Employee’s separation from service from the Company is effective May 2, 2014 (Separation Date). As of the Separation Date, Employee has no further privileges, duties or obligations to the Company or any of its affiliates, except as specifically provided herein.

2. SEVERANCE.

In the event Employee (a) executes and returns the Agreement to the Company no earlier than May 2, 2014 and no later than May 9, 2014 and (b) permits the Agreement to become effective, the Company will pay Employee a lump sum payment of SIX HUNDRED SIXTY SEVEN THOUSAND SEVEN HUNDRED SIXTY EIGHT DOLLARS AND NO CENTS ($667,768.00) less any amounts required to be withheld under applicable laws and regulations (Severance Payment). The Severance Payment will be paid as soon as practicable following the effectiveness of the Agreement, as determined under Section 21 (Effective Date), but not later than twenty-one (21) days following the Effective Date.

Employee covenants and agrees that the consideration set forth in this Section 2 is in full satisfaction of all sums owed to Employee, if any, by the Company and any current or former subsidiaries or affiliates of Southern Company (collectively, Southern Entities), upon Employee’s separation from service, except any benefits accrued as of Employee’s Separation Date under any Company-sponsored compensation or benefit plan or program, and constitutes good and complete consideration for the release, the non-disclosure and non-interference obligations under Section 8 and all other obligations and covenants of Employee contained herein, including, but not limited to, Section 7. Employee agrees that the agreement provides him valuable benefits to which he would not otherwise be entitled.

3. RELEASE BY EMPLOYEE.

Employee does hereby voluntarily and irrevocably waive, release, dismiss with prejudice, and withdraw all claims, complaints, suits or demands of any kind whatsoever (whether known or unknown) which he ever had, may have or now has against the Southern Entities, and their past, present and future officers, directors, employees, agents, insurers, attorneys, plan administrators and their respective benefit plans (and related trusts) (collectively, Releasees), arising from or relating to (directly or indirectly) Employee’s employment, his separation from service from the Company or other events that have occurred as of the date of execution of the Agreement, including but not limited to:

(a) claims for violations of Title VII of the Civil Rights Act of 1964, as amended; the Age Discrimination in Employment Act, as amended; the Fair Labor Standards Act; the Civil Rights Act of 1991; the Americans With Disabilities Act; the Equal Pay Act; the Civil Rights Act of 1866; the Family and Medical Leave Act; 42

U.S.C. § 1981; the National Labor Relations Act; the Labor Management Relations Act; executive orders, including Executive Orders 11246 and 11141; the Vietnam Era Veteran’s Readjustment Act of 1974; the Uniformed Services Employment and Reemployment Act of 1994; the Rehabilitation Act of 1973; the Sarbanes-Oxley Act of 2002, the Florida Civil Rights Act or the Employee Retirement Income Security Act of 1974;

(b) claims for violations of any other federal or state statute or regulation or local ordinance;

(c) claims for lost or unpaid wages, compensation or benefits, defamation, intentional or negligent infliction of emotional distress, assault, battery, wrongful or constructive discharge, negligent hiring, retention or supervision, fraud, misrepresentation, conversion, tortious interference, breach of contract or breach of fiduciary duty;

(d) claims to benefits under any bonus, severance, workforce reduction, early retirement, outplacement or any other similar type plan sponsored by the Company (except to the extent provided in Section 4); and

(e) any other claims under state law arising in tort or contract.

4. CLAIMS NOT RELEASED BY EMPLOYEE.

In signing the Agreement, Employee is not releasing any claims that may arise under the terms of the Agreement or which may arise out of events occurring after the date Employee executes the Agreement.

Employee also is not releasing claims to benefits that he is already entitled to receive under The Southern Company Pension Plan, The Southern Company Employee Savings Plan or under any of the Company’s other employee compensation or benefit plans or under any workers’ compensation laws. However, Employee understands and acknowledges that nothing herein is intended to or shall be construed to require the Company to institute or continue in effect any particular plan or benefit sponsored by the Company and the Company hereby reserves the right to amend or terminate any of its compensation or benefit programs at any time in accordance with the procedures set forth in such plans or programs.

5. NO ASSIGNMENT OF CERTAIN CLAIMS.

Employee represents that he has not assigned or transferred, or purported to assign or transfer, any claims or any portion thereof or interest therein to any party prior to the date of the Agreement.

6. PUBLICITY; NO DISPARAGING STATEMENT.

Employee and the Company covenant and agree that they shall not engage in any communications that shall disparage one another or interfere with their existing or prospective business relationships, except as otherwise provided in Section 11 hereof,

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7. NO EMPLOYMENT.

As substantial material inducement for the Company to enter into the Agreement, Employee agrees that he shall not 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 execution of the Agreement. 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 execution of the Agreement, unless an exceptional business reason exists for rehiring Employee and Southern Company’s senior Human Resources officer and Southern Company Services, Inc.’s Employee Relations Vice President and Associate General Counsel approve such rehiring.

8. BUSINESS PROTECTION PROVISIONS.

(a) Preamble.

As a material inducement to the Company to enter into the Agreement, and the recognition of the valuable experience, knowledge and proprietary information Employee gained from his employment with the Company, Employee warrants and agrees he will abide by and adhere to the following business protection provisions in this Section 8.

(b) Definitions.

For purposes of this Section 8, the following terms shall have the following meanings:

(i) 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 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; and (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.

(ii) 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.

(iii) 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,

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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.

(iv) Work Product shall mean all tangible work product, property, data, documentation, concepts or plans, inventions, improvements, techniques and processes 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.

(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 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 the 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 Separation Date (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 etseq., 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

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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.

(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 the Restricted Period, or within one year prior to the Separation Date, 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 clause (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 the Separation Date, 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 Separation Date. The restrictions set forth in this Section shall apply only to Entities with whom Employee had actual contact during the two (2) years prior to the Separation Date with a view toward the sale or providing of any product, equipment or service sold, provided or under development by the Company.

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(f) Non-Interference with Business.

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 the Agreement.

9. RETURN OF MATERIALS.

By no later than the effective date of the Agreement, Employee agrees to return to the Company all property of the Southern Entities, including but not limited to data, lists, information, memoranda, documents, identification cards, parking cards, keys, computers, fax machines, pagers, 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.

10. 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 or other Southern Entity to meaningfully respond to or address actual or threatened litigation, or government inquiries or investigations, or required filings with state, federal or foreign agencies (Company Matters). Upon request of the Company, and at any point following Employee’s 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.

11. CONFIDENTIALITY AND LEGAL PROCESS.

Employee represents and agrees that he will keep the terms, amount and fact of the Agreement confidential and that he will not hereafter disclose any information concerning the 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 Southern Entities. Notwithstanding the foregoing, nothing in this Section shall prohibit Employee from disclosing or discussing the 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 before Employee discloses any information to them about the Agreement. In addition, nothing in the 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 any legal and valid subpoena or other legal process. The Agreement is not intended in any way to proscribe

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Employee’s right and ability to provide information to any federal, state or local government in the lawful exercise of such governments’ governmental functions.

12. COMPENSATION.

Any Severance Payment paid to Employee under the Agreement shall not be considered compensation, as that term is defined in The Southern Company Employee Savings Plan or The Southern Company Pension Plan. Any payment under the Agreement shall not be considered wages, salary or compensation under any other employee benefit plan of the Company or any other Southern Entity.

13. SUCCESSORS AND ASSIGNS; APPLICABLE LAW.

The 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 Company and its 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. The Agreement shall be construed and interpreted in accordance with the laws of the State of Florida (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.

14. INTERPRETATION.

The judicial body interpreting the Agreement shall not construe the terms of the Agreement more strictly against one party, it being agreed that both parties and/or their attorneys or agents have negotiated and participated in the preparation hereof.

15. WAIVER OF BREACH; SPECIFIC PERFORMANCE.

The waiver of a breach of any provision of the Agreement shall not operate or be construed as a waiver of any other breach. Each of the parties to the Agreement will be entitled to enforce its or his rights under the Agreement, specifically, to recover damages by reason of any breach of any provision of the 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 the 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 the Agreement.

16. SEVERABILITY.

The unenforceability or invalidity of any particular provision of the 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 the 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

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provision as reformed. Employee acknowledges and agrees that the covenants and agreements contained in the Agreement 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 against any Southern Entity, whether predicated upon the Agreement or any other contract, shall not constitute a defense to the enforcement by the Company of said covenants and agreements.

17. COMPLETE AGREEMENT.

The 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. The Agreement may not be modified or amended except by a written instrument signed by both Employee and an authorized representative of the Company.

18. NO ADMISSION OF LIABILITY.

The Agreement shall not in any way be construed as an admission by the Company or Employee of any improper actions or liability whatsoever as to one another, and each specifically disclaims any liability to or improper actions against the other or any other person, on the part of itself or himself, its or his employees or agents.

19. NOTICES.

All notices required, necessary or desired to be given pursuant to the 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, or by such other manner or carrier that provides a record of delivery, and addressed to the party at the address set forth below:

If to Employee:	If to the Company:
PAUL BERNARD JACOB ADDRESS CONTAINED IN COMPANY RECORDS	Martha Tutchtone Human Resources Director Gulf Power Company One Energy Place Pensacola, FL

20. CONSIDERATION PERIOD.

The parties agree and understand that Employee has had at least twenty-one (21) days to consider the terms of the Agreement. EMPLOYEE AND THE COMPANY AGREE THAT ANY CHANGES WHETHER MATERIAL OR IMMATERIAL, WHICH ARE MADE TO THE COMPANY’S ORIGINAL OFFER OF CONSIDERATION IN EXCHANGE FOR THE AGREEMENT WILL NOT RESTART THE RUNNING OF THE 21-DAY CONSIDERATION PERIOD DESCRIBED IN THE PRECEDING SENTENCE.

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21. EFFECTIVE DATE OF AGREEMENT AND OPTION TO REVOKE.

The parties agree and understand that Employee may revoke the Agreement within seven (7) days after signing it. The last day upon which the Agreement can be revoked is referred to herein as the Last Revocation Day. Revocation shall be made by delivering a written notice of revocation to the Company as provided in Section 19. The parties agree and understand that if Employee executes and returns the Agreement in accordance with Section 2 and does not revoke the Agreement on or before the Last Revocation Day, the Agreement shall become effective on the day following the Last Revocation Day and Employee shall receive the Severance Payment described in Section 2 of the Agreement.

22. SURVIVAL.

Notwithstanding any expiration or termination of the Agreement, other than by revocation as provided in Section 21, the provisions of Sections 3, 4, 5, 6, 7,8, 10, 11, 13, 14, 15, 16, and 18 hereof shall survive and remain in full force and effect, as shall any other provision hereof that, by its terms or reasonable interpretation thereof, sets forth obligations that extend beyond the termination of the Agreement.

23. ACKNOWLEDGMENT OF KNOWING AND VOLUNTARY WAIVER.

Employee hereby represents and warrants that:

(a) Employee has CAREFULLY READ THE AGREEMENT AND FULLY UNDERSTANDS ALL OF THE PROVISIONS OF THE AGREEMENT;

(b) Employee has had an OPPORTUNITY TO CONSULT WITH AN ATTORNEY OF HIS CHOICE AS TO THE TERMS OF THE AGREEMENT to the full extent that he desired before signing the Agreement;

(c) Employee understands that the Agreement FOREVER RELEASES the Company from any legal action arising prior to the date of execution of the Agreement;

(d) Employee has had the opportunity to REVIEW AND CONSIDER THE AGREEMENT FOR A PERIOD OF AT LEAST TWENTY-ONE (21) DAYS before signing it;

(e) Employee understands that he SHALL HAVE SEVEN (7) CALENDAR DAYS FOLLOWING THE EXECUTION OF THE AGREEMENT TO REVOKE SAID AGREEMENT;

(f) In signing the Agreement, EMPLOYEE DOES NOT RELY ON NOR HAS HE RELIED ON ANY REPRESENTATION OR STATEMENT (WRITTEN OR ORAL) NOT SPECIFICALLY SET FORTH IN THE AGREEMENT by the Company or by any of the Company’s agents, representatives, or attorneys with regard to the subject matter, basis, or effect of the Agreement or otherwise; and

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(g) Employee was not coerced, threatened, or otherwise forced to sign the Agreement, and Employee is VOLUNTARILY SIGNING AND DELIVERING THE AGREEMENT of his own free will.

IN WITNESS WHEREOF, the undersigned have signed and executed the Agreement on the dates set forth below as an expression of their intent to be bound by the foregoing terms of the Agreement.

	COMPANY
ATTEST:	By:	/s/Stacy Kilcoyne
Officer's signature attested by:	Its:	VP Human Resources
/s/Melissa K. Caen	Date:	6/17/2014
	EMPLOYEE
	/s/P. Bernard Jacob
	Date:	5/2/2014

WITNESS:

Employee’s signature witnessed by:

/s/Jeffery A. Stone	Jeffery A. Stone
Signature	Printed Name of Witness
5/2/2014
Date

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EX-31.A1

Exhibit 31(a)1

THE SOUTHERN COMPANY

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, Thomas A. Fanning, certify that:

1. I have reviewed this quarterly report on Form 10-Q of The Southern Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  August 7, 2014

/s/Thomas A. Fanning

Thomas A. Fanning

Chairman, President and

Chief Executive Officer

EX-31.A2

Exhibit 31(a)2

THE SOUTHERN COMPANY

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, Art P. Beattie, certify that:

1. I have reviewed this quarterly report on Form 10-Q of The Southern Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  August 7, 2014

/s/Art P. Beattie

Art P. Beattie

Executive Vice President and Chief Financial Officer

EX-31.B1

Exhibit 31(b)1

ALABAMA POWER COMPANY

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, Mark A. Crosswhite, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Alabama Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  August 7, 2014

/s/Mark A. Crosswhite

Mark A. Crosswhite

Chairman, President and Chief Executive Officer

EX-31.B2

Exhibit 31(b)2

ALABAMA POWER COMPANY

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, Philip C. Raymond, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Alabama Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  August 7, 2014

/s/Philip C. Raymond

Philip C. Raymond

Executive Vice President, Chief Financial Officer

and Treasurer

EX-31.C1

Exhibit 31(c)1

GEORGIA POWER COMPANY

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, W. Paul Bowers, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Georgia Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 7, 2014

/s/W. Paul Bowers 

W. Paul Bowers

President and Chief Executive Officer

EX-31.C2

Exhibit 31(c)2

GEORGIA POWER COMPANY

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, W. Ron Hinson, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Georgia Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  August 7, 2014

/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:  August 7, 2014

/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:  August 7, 2014

/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:  August 7, 2014

/s/G. Edison Holland, Jr.

G. Edison Holland, Jr.

President, Chief Executive Officer and Chairman

EX-31.E2

Exhibit 31(e)2

MISSISSIPPI POWER COMPANY

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, Moses H. Feagin, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Mississippi Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  August 7, 2014 

/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: August 7, 2014

/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:  August 7, 2014

/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 June 30, 2014, we, the undersigned, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of our individual knowledge and belief, that:

(1) such Quarterly Report on Form 10-Q of The Southern Company for the quarter ended June 30, 2014, which this statement accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in such Quarterly Report on Form 10-Q of The Southern Company for the quarter ended June 30, 2014, fairly presents, in all material respects, the financial condition and results of operations of The Southern Company.

/s/Thomas A. Fanning

Thomas A. Fanning

Chairman, President and

Chief Executive Officer

/s/Art P. Beattie

Art P. Beattie

Executive Vice President and

Chief Financial Officer

August 7, 2014

EX-32.B

Exhibit 32(b)

CERTIFICATION

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the accompanying Quarterly Report on Form 10-Q of Alabama Power Company for the quarter ended June 30, 2014, we, the undersigned, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of our individual knowledge and belief, that:

(1) such Quarterly Report on Form 10-Q of Alabama Power Company for the quarter ended June 30, 2014, which this statement accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in such Quarterly Report on Form 10-Q of Alabama Power Company for the quarter ended June 30, 2014, fairly presents, in all material respects, the financial condition and results of operations of Alabama Power Company.

/s/Mark A. Crosswhite

Mark A. Crosswhite

Chairman, President and Chief Executive Officer

/s/Philip C. Raymond

Philip C. Raymond

Executive Vice President,

Chief Financial Officer and Treasurer

August 7, 2014

EX-32.C

Exhibit 32(c)

CERTIFICATION

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the accompanying Quarterly Report on Form 10-Q of Georgia Power Company for the quarter ended June 30, 2014, we, the undersigned, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of our individual knowledge and belief, that:

(1) such Quarterly Report on Form 10-Q of Georgia Power Company for the quarter ended June 30, 2014, which this statement accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in such Quarterly Report on Form 10-Q of Georgia Power Company for the quarter ended June 30, 2014, fairly presents, in all material respects, the financial condition and results of operations of Georgia Power Company.

/s/W. Paul Bowers

W. Paul Bowers

President and Chief Executive Officer

/s/W. Ron Hinson

W. Ron Hinson

Executive Vice President, Chief Financial Officer and Treasurer

August 7, 2014

EX-32.D

Exhibit 32(d)

CERTIFICATION

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the accompanying Quarterly Report on Form 10-Q of Gulf Power Company for the quarter ended June 30, 2014, we, the undersigned, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of our individual knowledge and belief, that:

(1) such Quarterly Report on Form 10-Q of Gulf Power Company for the quarter ended June 30, 2014, which this statement accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in such Quarterly Report on Form 10-Q of Gulf Power Company for the quarter ended June 30, 2014, 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

August 7, 2014

EX-32.E

Exhibit 32(e)

CERTIFICATION

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the accompanying Quarterly Report on Form 10-Q of Mississippi Power Company for the quarter ended June 30, 2014, we, the undersigned, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of our individual knowledge and belief, that:

(1) such Quarterly Report on Form 10-Q of Mississippi Power Company for the quarter ended June 30, 2014, which this statement accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in such Quarterly Report on Form 10-Q of Mississippi Power Company for the quarter ended June 30, 2014, 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.

President, Chief Executive Officer and Chairman

/s/Moses H. Feagin

Moses H. Feagin

Vice President, Treasurer and

Chief Financial Officer

August 7, 2014

EX-32.F

Exhibit 32(f)

CERTIFICATION

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the accompanying Quarterly Report on Form 10-Q of Southern Power Company for the quarter ended June 30, 2014, we, the undersigned, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of our individual knowledge and belief, that:

(1) such Quarterly Report on Form 10-Q of Southern Power Company for the quarter ended June 30, 2014, which this statement accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in such Quarterly Report on Form 10-Q of Southern Power Company for the quarter ended June 30, 2014, 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

August 7, 2014

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Retirement Benefits (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Pension Plans [Member] | Southern Company [Member]
Pension Plans and Postretirement Plans
Service cost	$ 54	$ 58	$ 107	$ 116
Interest cost	108	97	217	194
Expected return on plan assets	(162)	(150)	(323)	(301)
Amortization:
Prior service costs	7	6	13	13
Net (gain)/loss	27	50	55	100
Net cost	34	61	69	122
Pension Plans [Member] | Alabama Power [Member]
Pension Plans and Postretirement Plans
Service cost	12	14	24	27
Interest cost	26	23	52	46
Expected return on plan assets	(42)	(39)	(84)	(78)
Amortization:
Prior service costs	2	1	3	3
Net (gain)/loss	8	13	16	26
Net cost	6	12	11	24
Pension Plans [Member] | Georgia Power [Member]
Pension Plans and Postretirement Plans
Service cost	15	18	31	35
Interest cost	38	35	76	69
Expected return on plan assets	(56)	(53)	(113)	(106)
Amortization:
Prior service costs	2	2	5	5
Net (gain)/loss	10	18	20	37
Net cost	9	20	19	40
Pension Plans [Member] | Gulf Power [Member]
Pension Plans and Postretirement Plans
Service cost	1	2	4	5
Interest cost	5	5	10	9
Expected return on plan assets	(7)	(7)	(14)	(13)
Amortization:
Prior service costs	1	1	1	1
Net (gain)/loss	1	2	2	4
Net cost	1	3	3	6
Pension Plans [Member] | Mississippi Power [Member]
Pension Plans and Postretirement Plans
Service cost	2	2	5	5
Interest cost	5	4	10	9
Expected return on plan assets	(7)	(6)	(14)	(13)
Amortization:
Prior service costs	1	0	1	0
Net (gain)/loss	1	3	2	5
Net cost	2	3	4	6
Other Postretirement Benefits [Member] | Southern Company [Member]
Pension Plans and Postretirement Plans
Service cost	6	6	11	12
Interest cost	20	18	40	37
Expected return on plan assets	(15)	(14)	(30)	(28)
Amortization:
Transition obligation		1		2
Prior service costs	1	1	2	2
Net (gain)/loss	0	3	1	6
Net cost	12	15	24	31
Other Postretirement Benefits [Member] | Alabama Power [Member]
Pension Plans and Postretirement Plans
Service cost	2	1	3	3
Interest cost	5	4	10	9
Expected return on plan assets	(7)	(6)	(13)	(12)
Amortization:
Transition obligation		0		0
Prior service costs	1	1	2	2
Net (gain)/loss	0	1	0	1
Net cost	1	1	2	3
Other Postretirement Benefits [Member] | Georgia Power [Member]
Pension Plans and Postretirement Plans
Service cost	1	1	3	3
Interest cost	9	8	17	16
Expected return on plan assets	(7)	(6)	(13)	(12)
Amortization:
Transition obligation		1		2
Prior service costs	0	0	0	0
Net (gain)/loss	1	2	1	4
Net cost	4	6	8	13
Other Postretirement Benefits [Member] | Gulf Power [Member]
Pension Plans and Postretirement Plans
Service cost	1	1	1	1
Interest cost	1	0	2	1
Expected return on plan assets	(1)	0	(1)	0
Amortization:
Transition obligation		0		0
Prior service costs	0	0	0	0
Net (gain)/loss	0	0	0	0
Net cost	1	1	2	2
Other Postretirement Benefits [Member] | Mississippi Power [Member]
Pension Plans and Postretirement Plans
Service cost	1	1	1	1
Interest cost	1	1	2	2
Expected return on plan assets	(1)	(1)	(1)	(1)
Amortization:
Transition obligation		0		0
Prior service costs	0	0	0	0
Net (gain)/loss	0	0	0	0
Net cost	$ 1	$ 1	$ 2	$ 2

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Segment and Related Information - Financial Data for Products and Services (Details) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Revenue from External Customer [Line Items]
Electric Revenue	$ 4,454,000,000	$ 4,230,000,000	$ 9,081,000,000	$ 8,116,000,000
Financial data for Products and Services
Electric Utilities' Revenues	4,467,000,000	4,246,000,000	9,111,000,000	8,143,000,000
Retail [Member]
Revenue from External Customer [Line Items]
Electric Revenue	3,770,000,000	3,620,000,000	7,628,000,000	6,918,000,000
Wholesale [Member]
Revenue from External Customer [Line Items]
Electric Revenue	515,000,000	454,000,000	1,119,000,000	886,000,000
Other [Member]
Revenue from External Customer [Line Items]
Electric Revenue	$ 169,000,000	$ 156,000,000	$ 334,000,000	$ 312,000,000

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Acquisitions (Details) (Southern Power [Member], USD $) In Millions, unless otherwise specified	0 Months Ended	6 Months Ended
	May 22, 2014	Jun. 30, 2014	May 22, 2014 MW
Adobe Solar LLC [Member]
Business Acquisition [Line Items]
Noncontrolling Interest, Ownership Percentage by Parent		90.00%
Acquisitions (Textual) [Abstract]
Power of solar polycrystalline silicon facility		20
Beginning Year Of Output Of Constructed Plant1		2014
Life Output Of Plant		20 years
Cash Consideration for acquisition of the interests in Apex		$ 90.5
Business Acquisition Cost Paid Upon Achievement Of Milestones		4.7
Reimbursable Transmission Costs Receivable		13.4
Macho Springs LLC [Member]
Acquisitions (Textual) [Abstract]
Power of solar polycrystalline silicon facility			50
Beginning Year Of Output Of Constructed Plant1	2014
Life Output Of Plant		20 years
Cash Consideration for acquisition of the interests in Apex	$ 130.0

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Fair Value Measurements - Financial Instruments for which Carrying Amount did not Equal Fair Value (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2014
Southern Company [Member]
Long-term debt:
Long-term debt, Carrying Amount	$ 22,542
Long-term debt, Fair Value	23,883
Alabama Power [Member]
Long-term debt:
Long-term debt, Carrying Amount	6,229
Long-term debt, Fair Value	6,800
Georgia Power [Member]
Long-term debt:
Long-term debt, Carrying Amount	9,557
Long-term debt, Fair Value	10,112
Gulf Power [Member]
Long-term debt:
Long-term debt, Carrying Amount	1,246
Long-term debt, Fair Value	1,306
Mississippi Power [Member]
Long-term debt:
Long-term debt, Carrying Amount	2,577
Long-term debt, Fair Value	2,571
Southern Power [Member]
Long-term debt:
Long-term debt, Carrying Amount	1,629
Long-term debt, Fair Value	$ 1,752

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Derivatives (Tables)

6 Months Ended

Jun. 30, 2014

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of derivatives

At June 30, 2014, the net volume of energy-related derivative contracts for natural gas positions for the Southern Company system, together with the longest hedge date over which the respective entity is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest non-hedge date for derivatives not designated as hedges, were as follows:

	Net Purchased mmBtu	Longest Hedge Date	Longest Non-Hedge Date
	(in millions)
Southern Company	250	2018	2017
Alabama Power	63	2017	—
Georgia Power	50	2017	—
Gulf Power	85	2018	—
Mississippi Power	51	2017	—
Southern Power	1	—	2017

Notional amount of interest rate derivatives

At June 30, 2014, the following interest rate derivatives were outstanding:

	Notional Amount		Interest Rate Received	Weighted Average Interest Rate Paid	Hedge Maturity Date	Fair Value Gain (Loss) June 30, 2014
	(in millions)					(in millions)
Cash flow hedges of forecasted debt
Alabama Power	$	75	3-month LIBOR	3.12%	October 2025	$	—

Fair value of energy-related derivatives and interest rate derivatives

At June 30, 2014, the fair value of energy-related derivatives was reflected in the balance sheets as follows:

Asset Derivatives at June 30, 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	$	31	$	12	$	6	$	8	$	5
Other deferred charges and assets	9		2		1		4		2
Total asset derivatives	$	40	$	14	$	7	$	12	$	7	N/A

Liability Derivatives at June 30, 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:
Liabilities from risk management activities	$	19	$	2	$	11	$	4	$	2
Other deferred credits and liabilities	17		3		4		7		3
Total liability derivatives	$	36	$	5	$	15	$	11	$	5	N/A

At December 31, 2013, the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows:

Asset Derivatives at December 31, 2013
	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	$	16	$	5	$	3	$	5	$	3
Other deferred charges and assets	7		2		2		2		2
Total derivatives designated as hedging instruments for regulatory purposes	$	23	$	7	$	5	$	7	$	5	N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current assets	3		—		—		—		—		$	—
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other deferred charges and assets	1		—		—		—		—		1
Total asset derivatives	$	27	$	7	$	5	$	7	$	5	$	1

Liability Derivatives at December 31, 2013
	Fair Value
Derivative Category and Balance Sheet Location	Southern Company		Alabama Power		Georgia Power		Gulf Power		Mississippi Power		Southern Power
	(in millions)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Liabilities from risk management activities	$	26	$	3	$	13	$	6	$	4
Other deferred credits and liabilities	29		5		8		11		6
Total derivatives designated as hedging instruments for regulatory purposes	$	55	$	8	$	21	$	17	$	10	N/A
Derivatives not designated as hedging instruments
Energy-related derivatives:
Liabilities from risk management activities	1		—		—		—		—		$	1
Total liability derivatives	$	56	$	8	$	21	$	17	$	10	$	1

Offsetting disclosure tables

Interest rate derivatives presented in the tables above do not have amounts available for offset and are therefore excluded from the offsetting disclosure tables below.

Derivative Contracts at June 30, 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)	$	40		$	14		$	7		$	12		$	7		$	—
Gross amounts not offset in the Balance Sheet (b)	(30		)	(5		)	(7		)	(8		)	(4		)	—
Net energy-related derivative assets	$	10		$	9		$	—		$	4		$	3		$	—
Liabilities
Energy-related derivatives:
Energy-related derivatives presented in the Balance Sheet (a)	$	36		$	5		$	15		$	11		$	5		$	—
Gross amounts not offset in the Balance Sheet (b)	(30		)	(5		)	(7		)	(8		)	(4		)	—
Net energy-related derivative liabilities	$	6		$	—		$	8		$	3		$	1		$	—

(a) None of the registrants offset 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, 2013
	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)	$	24		$	7		$	5		$	7		$	5		$	1
Gross amounts not offset in the Balance Sheet (b)	(22		)	(5		)	(5		)	(6		)	(4		)	—
Net energy-related derivative assets	$	2		$	2		$	—		$	1		$	1		$	1
Liabilities
Energy-related derivatives:
Energy-related derivatives presented in the Balance Sheet (a)	$	56		$	8		$	21		$	17		$	10		$	1
Gross amounts not offset in the Balance Sheet (b)	(22		)	(5		)	(5		)	(6		)	(4		)	—
Net energy-related derivative liabilities	$	34		$	3		$	16		$	11		$	6		$	1

(a) None of the registrants offset 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 effect of unrealized derivative gains (losses)

At June 30, 2014 and December 31, 2013, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred on the balance sheets were as follows:

Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet at June 30, 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	$	(19	)	$	(2	)	$	(11	)	$	(4	)	$	(2	)
Other regulatory assets, deferred	(17		)	(3		)	(4		)	(7		)	(3		)
Other regulatory liabilities, current	31			12			6			8			5
Other regulatory liabilities, deferred	9			2			1			4			2
Total energy-related derivative gains (losses)	$	4		$	9		$	(8	)	$	1		$	2

Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet at December 31, 2013
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	$	(26	)	$	(3	)	$	(13	)	$	(6	)	$	(4	)
Other regulatory assets, deferred	(29		)	(5		)	(8		)	(11		)	(6		)
Other regulatory liabilities, current	16			5			3			5			3
Other regulatory liabilities, deferred (a)	7			2			2			2			2
Total energy-related derivative gains (losses)	$	(32	)	$	(1	)	$	(16	)	$	(10	)	$	(5	)

(a) Georgia Power includes Other regulatory liabilities, deferred in Other deferred credits and liabilities.

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Derivatives - Balance Sheet Presentation (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2014	Dec. 31, 2013
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		$ 27
Derivative Liability, Fair Value, Gross Liability		56
Hedging Instruments for Regulatory Purposes [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		23
Derivative Liability, Fair Value, Gross Liability		55
Energy Related Derivative [Member] | Hedging Instruments for Regulatory Purposes [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		26
Energy Related Derivative [Member] | Hedging Instruments for Regulatory Purposes [Member] | Other deferred credits and liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		29
Energy Related Derivative [Member] | Hedging Instruments for Regulatory Purposes [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		16
Energy Related Derivative [Member] | Hedging Instruments for Regulatory Purposes [Member] | Other deferred charges and assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		7
Energy Related Derivative [Member] | Not Designated as Hedging Instrument [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		1
Energy Related Derivative [Member] | Not Designated as Hedging Instrument [Member] | Other deferred charges and assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		1
Interest Rate Contract [Member] | Cash Flow and Fair Value Hedging [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		3
Southern Company [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	40
Derivative Liability, Fair Value, Gross Liability	36
Southern Company [Member] | Energy Related Derivative [Member] | Hedging Instruments for Regulatory Purposes [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	19
Southern Company [Member] | Energy Related Derivative [Member] | Hedging Instruments for Regulatory Purposes [Member] | Other deferred credits and liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	17
Southern Company [Member] | Energy Related Derivative [Member] | Hedging Instruments for Regulatory Purposes [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	31
Southern Company [Member] | Energy Related Derivative [Member] | Hedging Instruments for Regulatory Purposes [Member] | Other deferred charges and assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	9
Alabama Power [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	14	7
Derivative Liability, Fair Value, Gross Liability	5	8
Alabama Power [Member] | Hedging Instruments for Regulatory Purposes [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		7
Derivative Liability, Fair Value, Gross Liability		8
Alabama Power [Member] | Energy Related Derivative [Member] | Hedging Instruments for Regulatory Purposes [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	2	3
Alabama Power [Member] | Energy Related Derivative [Member] | Hedging Instruments for Regulatory Purposes [Member] | Other deferred credits and liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	3	5
Alabama Power [Member] | Energy Related Derivative [Member] | Hedging Instruments for Regulatory Purposes [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	12	5
Alabama Power [Member] | Energy Related Derivative [Member] | Hedging Instruments for Regulatory Purposes [Member] | Other deferred charges and assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	2	2
Alabama Power [Member] | Energy Related Derivative [Member] | Not Designated as Hedging Instrument [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0
Alabama Power [Member] | Energy Related Derivative [Member] | Not Designated as Hedging Instrument [Member] | Other deferred charges and assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0
Alabama Power [Member] | Interest Rate Contract [Member] | Cash Flow and Fair Value Hedging [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0
Georgia Power [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	7	5
Derivative Liability, Fair Value, Gross Liability	15	21
Georgia Power [Member] | Hedging Instruments for Regulatory Purposes [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		5
Derivative Liability, Fair Value, Gross Liability		21
Georgia Power [Member] | Energy Related Derivative [Member] | Hedging Instruments for Regulatory Purposes [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	11	13
Georgia Power [Member] | Energy Related Derivative [Member] | Hedging Instruments for Regulatory Purposes [Member] | Other deferred credits and liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	4	8
Georgia Power [Member] | Energy Related Derivative [Member] | Hedging Instruments for Regulatory Purposes [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	6	3
Georgia Power [Member] | Energy Related Derivative [Member] | Hedging Instruments for Regulatory Purposes [Member] | Other deferred charges and assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	1	2
Georgia Power [Member] | Energy Related Derivative [Member] | Not Designated as Hedging Instrument [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0
Georgia Power [Member] | Energy Related Derivative [Member] | Not Designated as Hedging Instrument [Member] | Other deferred charges and assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0
Georgia Power [Member] | Interest Rate Contract [Member] | Cash Flow and Fair Value Hedging [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0
Gulf Power [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	12	7
Derivative Liability, Fair Value, Gross Liability	11	17
Gulf Power [Member] | Hedging Instruments for Regulatory Purposes [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		7
Derivative Liability, Fair Value, Gross Liability		17
Gulf Power [Member] | Energy Related Derivative [Member] | Hedging Instruments for Regulatory Purposes [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	4	6
Gulf Power [Member] | Energy Related Derivative [Member] | Hedging Instruments for Regulatory Purposes [Member] | Other deferred credits and liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	7	11
Gulf Power [Member] | Energy Related Derivative [Member] | Hedging Instruments for Regulatory Purposes [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	8	5
Gulf Power [Member] | Energy Related Derivative [Member] | Hedging Instruments for Regulatory Purposes [Member] | Other deferred charges and assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	4	2
Gulf Power [Member] | Energy Related Derivative [Member] | Not Designated as Hedging Instrument [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0
Gulf Power [Member] | Energy Related Derivative [Member] | Not Designated as Hedging Instrument [Member] | Other deferred charges and assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0
Gulf Power [Member] | Interest Rate Contract [Member] | Cash Flow and Fair Value Hedging [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0
Mississippi Power [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	7	5
Derivative Liability, Fair Value, Gross Liability	5	10
Mississippi Power [Member] | Hedging Instruments for Regulatory Purposes [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		5
Derivative Liability, Fair Value, Gross Liability		10
Mississippi Power [Member] | Energy Related Derivative [Member] | Hedging Instruments for Regulatory Purposes [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	2	4
Mississippi Power [Member] | Energy Related Derivative [Member] | Hedging Instruments for Regulatory Purposes [Member] | Other deferred credits and liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	3	6
Mississippi Power [Member] | Energy Related Derivative [Member] | Hedging Instruments for Regulatory Purposes [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	5	3
Mississippi Power [Member] | Energy Related Derivative [Member] | Hedging Instruments for Regulatory Purposes [Member] | Other deferred charges and assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	2	2
Mississippi Power [Member] | Energy Related Derivative [Member] | Not Designated as Hedging Instrument [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		0
Mississippi Power [Member] | Energy Related Derivative [Member] | Not Designated as Hedging Instrument [Member] | Other deferred charges and assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0
Mississippi Power [Member] | Interest Rate Contract [Member] | Cash Flow and Fair Value Hedging [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0
Southern Power [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		1
Derivative Liability, Fair Value, Gross Liability		1
Southern Power [Member] | Energy Related Derivative [Member] | Not Designated as Hedging Instrument [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		1
Southern Power [Member] | Energy Related Derivative [Member] | Not Designated as Hedging Instrument [Member] | Other deferred charges and assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		1
Southern Power [Member] | Interest Rate Contract [Member] | Cash Flow and Fair Value Hedging [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		$ 0

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Financing (Details) (USD $)						1 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2014 Southern Company [Member]	Jun. 30, 2014 Alabama Power [Member]	Jun. 30, 2014 Georgia Power [Member]	Jun. 30, 2014 Gulf Power [Member]	May 31, 2014 Mississippi Power [Member]	Jan. 31, 2014 Mississippi Power [Member]	Jun. 30, 2014 Mississippi Power [Member]	Jun. 30, 2014 Southern Power [Member]	Jun. 30, 2014 Other Subsidiaries [Member]	Apr. 01, 2014 Debt Issuances [Member] Gulf Power [Member]	Apr. 01, 2014 Debt Redemptions [Member] Gulf Power [Member]
Line of Credit Facility [Line Items]
Long-term Pollution Control Bond											$ 29,075,000.000	$ 29,075,000.000
Bank Loans Period Of Extension						19 months	18 months
Credit arrangements by company
Expires, 2014	223,000,000	0	163,000,000	0	20,000,000			40,000,000	0	0
Expires, 2015	335,000,000	0	110,000,000	0	60,000,000			95,000,000	0	70,000,000
Expires, 2016	480,000,000	0	0	150,000,000	165,000,000			165,000,000	0	0
Line Of Credit Expire Year Four	30,000,000	0	0	0	30,000,000			0	0	0
Expires, 2018	4,130,000,000	1,000,000,000	1,030,000,000	1,600,000,000	0			0	500,000,000	0
Total	5,198,000,000	1,000,000,000	1,303,000,000	1,750,000,000	275,000,000			300,000,000	500,000,000	70,000,000
Unused	5,183,000,000	1,000,000,000	1,303,000,000	1,736,000,000	275,000,000			300,000,000	499,000,000	70,000,000
Executable Term-Loans, One Year	148,000,000	0	53,000,000	0	50,000,000			25,000,000	0	20,000,000
Executable Term-Loans, Two Years	40,000,000	0	0	0	0			40,000,000	0	0
Due Within One Year, Term Out	188,000,000	0	53,000,000	0	50,000,000			65,000,000	0	20,000,000
Due Within One Year, No Term Out	310,000,000	0	185,000,000	0	30,000,000			70,000,000	0	25,000,000
Debt Instrument, Description of Variable Rate Basis								P1M
Aggregate Principal Amount Of Floating Rate Bank Loan						$ 220,000,000	$ 250,000,000

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Segment and Related Information - Financial Data for Business Segments (Details) (USD $)	3 Months Ended				6 Months Ended					3 Months Ended				6 Months Ended					3 Months Ended				6 Months Ended					3 Months Ended		6 Months Ended		3 Months Ended				6 Months Ended					3 Months Ended				6 Months Ended					3 Months Ended				6 Months Ended					3 Months Ended				6 Months Ended					3 Months Ended	6 Months Ended		12 Months Ended
	Jun. 30, 2014 state		Jun. 30, 2013		Jun. 30, 2014 state		Jun. 30, 2013		Dec. 31, 2013	Jun. 30, 2014 Electric Utilities [Member]		Jun. 30, 2013 Electric Utilities [Member]		Jun. 30, 2014 Electric Utilities [Member]		Jun. 30, 2013 Electric Utilities [Member]		Dec. 31, 2013 Electric Utilities [Member]	Jun. 30, 2014 Traditional Operating Companies [Member] Electric Utilities [Member]		Jun. 30, 2013 Traditional Operating Companies [Member] Electric Utilities [Member]		Jun. 30, 2014 Traditional Operating Companies [Member] Electric Utilities [Member]		Jun. 30, 2013 Traditional Operating Companies [Member] Electric Utilities [Member]		Dec. 31, 2013 Traditional Operating Companies [Member] Electric Utilities [Member]	Jun. 30, 2014 Southern Power [Member]	Jun. 30, 2013 Southern Power [Member]	Jun. 30, 2014 Southern Power [Member]	Jun. 30, 2013 Southern Power [Member]	Jun. 30, 2014 Southern Power [Member] Electric Utilities [Member]		Jun. 30, 2013 Southern Power [Member] Electric Utilities [Member]		Jun. 30, 2014 Southern Power [Member] Electric Utilities [Member]		Jun. 30, 2013 Southern Power [Member] Electric Utilities [Member]		Dec. 31, 2013 Southern Power [Member] Electric Utilities [Member]	Jun. 30, 2014 Eliminations [Member]		Jun. 30, 2013 Eliminations [Member]		Jun. 30, 2014 Eliminations [Member]		Jun. 30, 2013 Eliminations [Member]		Dec. 31, 2013 Eliminations [Member]	Jun. 30, 2014 Eliminations [Member] Electric Utilities [Member]		Jun. 30, 2013 Eliminations [Member] Electric Utilities [Member]		Jun. 30, 2014 Eliminations [Member] Electric Utilities [Member]		Jun. 30, 2013 Eliminations [Member] Electric Utilities [Member]		Dec. 31, 2013 Eliminations [Member] Electric Utilities [Member]	Jun. 30, 2014 All Other [Member]		Jun. 30, 2013 All Other [Member]		Jun. 30, 2014 All Other [Member]		Jun. 30, 2013 All Other [Member]		Dec. 31, 2013 All Other [Member]	Jun. 30, 2013 Kemper Igcc [Member]	Jun. 30, 2014 Kemper Igcc [Member]	Jun. 30, 2013 Kemper Igcc [Member]	Dec. 31, 2013 Kemper Igcc [Member]
Segment Reporting Information [Line Items]
Number of States in which Entity Operates	4				4
Segment and Related Information (Textual) [Abstract]
Electric Utilities' Revenues	$ 4,467,000,000		$ 4,246,000,000		$ 9,111,000,000		$ 8,143,000,000			$ 4,454,000,000		$ 4,230,000,000		$ 9,081,000,000		$ 8,116,000,000			$ 4,209,000,000		$ 4,018,000,000		$ 8,587,000,000		$ 7,687,000,000			$ 68,000,000	$ 89,000,000	$ 140,000,000	$ 167,000,000	$ 329,000,000		$ 307,000,000		$ 680,000,000		$ 610,000,000			$ (26,000,000)		$ (22,000,000)		$ (50,000,000)		$ (46,000,000)			$ (84,000,000)		$ (95,000,000)		$ (186,000,000)		$ (181,000,000)			$ 39,000,000		$ 38,000,000		$ 80,000,000		$ 73,000,000
Financial data for business segments
Electric Utilities' Revenues	4,467,000,000		4,246,000,000		9,111,000,000		8,143,000,000			4,454,000,000		4,230,000,000		9,081,000,000		8,116,000,000			4,209,000,000		4,018,000,000		8,587,000,000		7,687,000,000			68,000,000	89,000,000	140,000,000	167,000,000	329,000,000		307,000,000		680,000,000		610,000,000			(26,000,000)		(22,000,000)		(50,000,000)		(46,000,000)			(84,000,000)		(95,000,000)		(186,000,000)		(181,000,000)			39,000,000		38,000,000		80,000,000		73,000,000
Segment net income (loss)	611,000,000	[1],[2]	297,000,000	[1],[2]	962,000,000	[1],[3]	378,000,000	[1],[3]		611,000,000	[1],[2]	296,000,000	[1],[2]	963,000,000	[1],[3]	391,000,000	[1],[3]		580,000,000	[1],[2]	268,000,000	[1],[2]	899,000,000	[1],[3]	334,000,000	[1],[3]						31,000,000	[1],[2]	28,000,000	[1],[2]	64,000,000	[1],[3]	57,000,000	[1],[3]		(2,000,000)	[1],[2]	(3,000,000)	[1],[2]	(3,000,000)	[1],[3]	(1,000,000)	[1],[3]		0	[1],[2]	0	[1],[2]	0	[1],[3]	0	[1],[3]		2,000,000	[1],[2]	4,000,000	[1],[2]	2,000,000	[1],[3]	(12,000,000)	[1],[3]
Total assets	66,400,000,000				66,400,000,000				64,546,000,000	65,683,000,000				65,683,000,000				63,775,000,000	61,210,000,000				61,210,000,000				59,447,000,000					4,605,000,000				4,605,000,000				4,429,000,000	(639,000,000)				(639,000,000)				(306,000,000)	(132,000,000)				(132,000,000)				(101,000,000)	1,356,000,000				1,356,000,000				1,077,000,000
Pre-tax charge to income																																																																				450,000,000	380,000,000	990,000,000	1,180,000,000
After tax charge to income																																																																				$ 277,900,000	$ 234,700,000	$ 611,300,000	$ 728,700,000

[1] After dividends on preferred and preference stock of subsidiaries.

[2] Segment net income (loss) for the traditional operating companies for the three months ended June 30, 2013 includes a $450.0 million pre-tax charge ($277.9 million after tax) for an estimated probable loss on the Kemper IGCC. See Note (B) under "Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" herein for additional information.

[3] Segment net income (loss) for the traditional operating companies for the six months ended June 30, 2014 and June 30, 2013 includes $380.0 million in pre-tax charges ($234.7 million after tax) and $990.0 million in pre-tax charges ($611.3 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.

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Introduction

6 Months Ended

Jun. 30, 2014

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, 2013 have been derived from the audited financial statements of each registrant. In the opinion of each registrant's management, the information regarding such registrant furnished herein reflects all adjustments, which, except as otherwise disclosed, are of a normal recurring nature, necessary to present fairly the results of operations for the periods ended June 30, 2014 and 2013. 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.

Depreciation

Beginning in 2014, Southern Power changed the method of depreciation for its property, plant, and equipment from composite depreciation to component depreciation. As a result, certain generation assets are depreciated on a units-of-production basis to better match outage and maintenance costs to the usage of, and revenues from, these assets. The difference in depreciation expense under this method was not material in the first and second quarters 2014 and is not expected to have a material impact on the financial statements of Southern Company or Southern Power in future periods.

Recently Issued Accounting Standards

On May 28, 2014, the Financial Accounting Standards Board issued ASC 606, Revenue from Contracts with Customers. ASC 606 revises the accounting for revenue recognition and is effective for fiscal years beginning after December 15, 2016. The registrants are currently evaluating the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined.

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Derivatives - Balance Sheet Offsetting (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2014		Dec. 31, 2013
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset			$ 27
Derivative Liability, Fair Value, Gross Liability			56
Southern Company [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	40
Derivative Liability, Fair Value, Gross Liability	36
Alabama Power [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	14		7
Derivative Liability, Fair Value, Gross Liability	5		8
Georgia Power [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	7		5
Derivative Liability, Fair Value, Gross Liability	15		21
Gulf Power [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	12		7
Derivative Liability, Fair Value, Gross Liability	11		17
Mississippi Power [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	7		5
Derivative Liability, Fair Value, Gross Liability	5		10
Southern Power [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset			1
Derivative Liability, Fair Value, Gross Liability			1
Energy Related Derivative [Member] | Southern Company [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Amount Offset Against Collateral	10		2
Derivative Liability, Fair Value, Amount Offset Against Collateral	6		34
Energy Related Derivative [Member] | Alabama Power [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Amount Offset Against Collateral	9		2
Derivative Liability, Fair Value, Amount Offset Against Collateral	0		3
Energy Related Derivative [Member] | Georgia Power [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Amount Offset Against Collateral	0		0
Derivative Liability, Fair Value, Amount Offset Against Collateral	8		16
Energy Related Derivative [Member] | Gulf Power [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Amount Offset Against Collateral	4		1
Derivative Liability, Fair Value, Amount Offset Against Collateral	3		11
Energy Related Derivative [Member] | Mississippi Power [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Amount Offset Against Collateral	3		1
Derivative Liability, Fair Value, Amount Offset Against Collateral	1		6
Energy Related Derivative [Member] | Southern Power [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Amount Offset Against Collateral	0		1
Derivative Liability, Fair Value, Amount Offset Against Collateral	0		1
Energy Related Derivative [Member] | Net Amount Of Derivatives [Member] | Southern Company [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	40	[1]	24	[2]
Derivative Liability, Fair Value, Gross Liability	36	[1]	56	[2]
Energy Related Derivative [Member] | Net Amount Of Derivatives [Member] | Alabama Power [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	14	[1]	7	[2]
Derivative Liability, Fair Value, Gross Liability	5	[1]	8	[2]
Energy Related Derivative [Member] | Net Amount Of Derivatives [Member] | Georgia Power [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	7	[1]	5	[2]
Derivative Liability, Fair Value, Gross Liability	15	[1]	21	[2]
Energy Related Derivative [Member] | Net Amount Of Derivatives [Member] | Gulf Power [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	12	[1]	7	[2]
Derivative Liability, Fair Value, Gross Liability	11	[1]	17	[2]
Energy Related Derivative [Member] | Net Amount Of Derivatives [Member] | Mississippi Power [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	7	[1]	5	[2]
Derivative Liability, Fair Value, Gross Liability	5	[1]	10	[2]
Energy Related Derivative [Member] | Net Amount Of Derivatives [Member] | Southern Power [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	[1]	1	[2]
Derivative Liability, Fair Value, Gross Liability	0	[1]	1	[2]
Energy Related Derivative [Member] | Gross Amount Of Derivatives [Member] | Southern Company [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	(30)	[3]	(22)	[4]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	(30)	[3]	(22)	[4]
Energy Related Derivative [Member] | Gross Amount Of Derivatives [Member] | Alabama Power [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	(5)	[3]	(5)	[4]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	(5)	[3]	(5)	[4]
Energy Related Derivative [Member] | Gross Amount Of Derivatives [Member] | Georgia Power [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	(7)	[3]	(5)	[4]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	(7)	[3]	(5)	[4]
Energy Related Derivative [Member] | Gross Amount Of Derivatives [Member] | Gulf Power [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	(8)	[3]	(6)	[4]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	(8)	[3]	(6)	[4]
Energy Related Derivative [Member] | Gross Amount Of Derivatives [Member] | Mississippi Power [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	(4)	[3]	(4)	[4]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	(4)	[3]	(4)	[4]
Energy Related Derivative [Member] | Gross Amount Of Derivatives [Member] | Southern Power [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	0	[3]	0	[4]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	$ 0	[3]	$ 0	[4]

[1] None of the registrants offset 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] (a) None of the registrants offset 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.

[3] 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, 2013 Fair Value SouthernCompany AlabamaPower GeorgiaPower GulfPower MississippiPower SouthernPower (in millions)Assets Energy-related derivatives: Energy-related derivatives presented in the Balance Sheet (a) $24 $7 $5 $7 $5 $1Gross amounts not offset in the Balance Sheet (b) (22) (5) (5) (6) (4) —Net energy-related derivative assets $2 $2 $— $1 $1 $1Liabilities Energy-related derivatives: Energy-related derivatives presented in the Balance Sheet (a) $56 $8 $21 $17 $10 $1Gross amounts not offset in the Balance Sheet (b) (22) (5) (5) (6) (4) —Net energy-related derivative liabilities $34 $3 $16 $11 $6 $1

[4] (b) 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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Contingencies and Regulatory Matters Current And Actual Cost Estimate (Details) (Kemper Igcc [Member], Mississippi Power [Member], USD $) In Billions, unless otherwise specified	6 Months Ended		12 Months Ended
	Jun. 30, 2014		Dec. 31, 2012
Loss Contingencies [Line Items]
Estimated Cost	$ 3.81	[1]	$ 2.88
Cost Of Lignite Mine And Equipment	0.23
Cost Of CO2 Pipeline Facilities	0.10
Cost Of AFUDC	0.37	[2],[3]
Plant General Exceptions	0.07
Plant Regulatory Asset	0.09	[3],[4]
Maximum Cap Construction Cost	4.67	[1],[3]
Project Estimate [Member]
Loss Contingencies [Line Items]
Estimated Cost	2.40	[1]
Cost Of Lignite Mine And Equipment	0.21
Cost Of CO2 Pipeline Facilities	0.14
Cost Of AFUDC	0.17	[2],[3]
Plant General Exceptions	0.05
Plant Regulatory Asset	0	[3],[4]
Maximum Cap Construction Cost	2.97	[1],[3]
Current Estimate [Member]
Loss Contingencies [Line Items]
Estimated Cost	4.44	[1]
Cost Of Lignite Mine And Equipment	0.24
Cost Of CO2 Pipeline Facilities	0.11
Cost Of AFUDC	0.55	[2],[3]
Plant General Exceptions	0.10
Plant Regulatory Asset	0.12	[3],[4]
Maximum Cap Construction Cost	$ 5.56	[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.

[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."

[3] Amounts in the Current Estimate reflect costs through May 31, 2015, but do not reflect any adjustments as a result of the expected placement of the combined cycle and the associated common facilities portion of the Kemper IGCC in service in the summer of 2014.

[4] 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."

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Contingencies and Regulatory Matters Cost Recovery Clause (Details) (Gulf Power [Member], USD $) In Millions, unless otherwise specified	Jun. 30, 2014	Dec. 31, 2013
Loss Contingencies [Line Items]
Under Recovered Fuel Cost	$ 43.4
Under Recovered Regulatory Clause Revenues [Member]
Loss Contingencies [Line Items]
Under Recovered Fuel Cost	43.4	21.0
Under Recovered Purchased Power Capacity Costs	0	2.8
Under Recovered Environmental Cost	15.1	14.4
Under Recovered Energy Conservation Costs	4.9	7.0
Other regulatory liabilities current [Member]
Loss Contingencies [Line Items]
Over Recovered Purchased Power Capacity Costs	$ 9.1	$ 0

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Derivatives - Pre-tax Effects of Derivatives Designated as Cash Flow Hedging Instruments (Details) (Energy Related Derivative [Member], USD $) In Millions, unless otherwise specified	Jun. 30, 2014	Dec. 31, 2013
Southern Company [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	$ 4	$ (32)
Alabama Power [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	9	(1)
Georgia Power [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	(8)	(16)
Gulf Power [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	1	(10)
Mississippi Power [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	2	(5)
Other regulatory assets current [Member] | Southern Company [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	(19)	(26)
Other regulatory assets current [Member] | Alabama Power [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	(2)	(3)
Other regulatory assets current [Member] | Georgia Power [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	(11)	(13)
Other regulatory assets current [Member] | Gulf Power [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	(4)	(6)
Other regulatory assets current [Member] | Mississippi Power [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	(2)	(4)
Other regulatory assets deferred [Member] | Southern Company [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	(17)	(29)
Other regulatory assets deferred [Member] | Alabama Power [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	(3)	(5)
Other regulatory assets deferred [Member] | Georgia Power [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	(4)	(8)
Other regulatory assets deferred [Member] | Gulf Power [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	(7)	(11)
Other regulatory assets deferred [Member] | Mississippi Power [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	(3)	(6)
Other regulatory liabilities current [Member] | Southern Company [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	31	16
Other regulatory liabilities current [Member] | Alabama Power [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	12	5
Other regulatory liabilities current [Member] | Georgia Power [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	6	3
Other regulatory liabilities current [Member] | Gulf Power [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	8	5
Other regulatory liabilities current [Member] | Mississippi Power [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	5	3
Other regulatory liabilities deferred [Member] | Southern Company [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	9	7
Other regulatory liabilities deferred [Member] | Alabama Power [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	2	2
Other regulatory liabilities deferred [Member] | Georgia Power [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	1	2
Other regulatory liabilities deferred [Member] | Gulf Power [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	4	2
Other regulatory liabilities deferred [Member] | Mississippi Power [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	$ 2	$ 2

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Contingencies and Regulatory Matters (Details) (USD $)	6 Months Ended	3 Months Ended		6 Months Ended			0 Months Ended	3 Months Ended		6 Months Ended		12 Months Ended					6 Months Ended		3 Months Ended		6 Months Ended		0 Months Ended		1 Months Ended		3 Months Ended		6 Months Ended		12 Months Ended										0 Months Ended	12 Months Ended	3 Months Ended	6 Months Ended		12 Months Ended	3 Months Ended		6 Months Ended		12 Months Ended			6 Months Ended		12 Months Ended					0 Months Ended		0 Months Ended
	Jun. 30, 2014	Jun. 30, 2014 Alabama Power [Member]	Jun. 30, 2013 Alabama Power [Member]	Jun. 30, 2014 Alabama Power [Member]	Jun. 30, 2013 Alabama Power [Member]	Dec. 31, 2013 Alabama Power [Member]	May 20, 2014 Georgia Power [Member] Purchased_Power_Agreement WindFarms	Jun. 30, 2014 Georgia Power [Member]	Jun. 30, 2013 Georgia Power [Member]	Jun. 30, 2014 Georgia Power [Member]	Jun. 30, 2013 Georgia Power [Member]	Dec. 31, 2013 Georgia Power [Member]	Jan. 02, 2014 Georgia Power [Member]	Jan. 02, 2013 Georgia Power [Member]	Jan. 02, 2012 Georgia Power [Member]	Jan. 02, 2011 Georgia Power [Member]	Jun. 30, 2014 Georgia Power [Member] Minimum [Member]	Jun. 30, 2014 Georgia Power [Member] Maximum [Member]	Jun. 30, 2014 Gulf Power [Member]	Jun. 30, 2013 Gulf Power [Member]	Jun. 30, 2014 Gulf Power [Member] clause	Jun. 30, 2013 Gulf Power [Member]	Jun. 24, 2014 Mississippi Power [Member]	May 20, 2014 Mississippi Power [Member]	Mar. 31, 2013 Mississippi Power [Member]	Mar. 31, 2012 Mississippi Power [Member]	Jun. 30, 2014 Mississippi Power [Member]	Jun. 30, 2013 Mississippi Power [Member]	Jun. 30, 2014 Mississippi Power [Member]	Jun. 30, 2013 Mississippi Power [Member]	Dec. 31, 2013 Mississippi Power [Member]	Dec. 31, 2012 Mississippi Power [Member]	May 06, 2014 Mississippi Power [Member]	Apr. 01, 2014 Mississippi Power [Member]	Jan. 02, 2014 Mississippi Power [Member]	Dec. 31, 2010 Mississippi Power [Member]	Jan. 31, 2013 Mississippi Power [Member] Maximum [Member]	Jun. 30, 2014 Gulf Power and Mississippi Power [Member]	May 20, 2014 Wind Farm [Member] Georgia Power [Member] MW	Jan. 10, 2014 Plant Mitchell Unit 3 [Member] Georgia Power [Member] MW	Feb. 26, 2013 Electricity Generation Plant, Non-Nuclear [Member] Mississippi Power [Member]	Dec. 31, 2012 Electricity Generation Plant, Non-Nuclear [Member] Mississippi Power [Member]	Jun. 30, 2013 Kemper IGCC [Member]	Jun. 30, 2014 Kemper IGCC [Member]	Jun. 30, 2013 Kemper IGCC [Member]	Dec. 31, 2013 Kemper IGCC [Member]	Mar. 31, 2014 Kemper IGCC [Member] Mississippi Power [Member]	Mar. 31, 2013 Kemper IGCC [Member] Mississippi Power [Member]	Jun. 30, 2014 Kemper IGCC [Member] Mississippi Power [Member]		Dec. 31, 2013 Kemper IGCC [Member] Mississippi Power [Member]	Dec. 31, 2012 Kemper IGCC [Member] Mississippi Power [Member]	Jun. 30, 2013 Kemper IGCC [Member] Mississippi Power [Member] MW	Jun. 30, 2014 Kemper IGCC [Member] Mississippi Power [Member] Minimum [Member]	Jun. 30, 2014 Kemper IGCC [Member] Mississippi Power [Member] Maximum [Member]	Dec. 31, 2010 Mine [Member] Mississippi Power [Member]	Jun. 30, 2014 Other deferred charges and assets [Member] Georgia Power [Member]	Dec. 31, 2013 Current Liabilities And Other Deferred Credits And Liabilities [Member] Georgia Power [Member]	Jun. 30, 2014 Storm Reserve [Member] Georgia Power [Member]	Dec. 31, 2013 Storm Reserve [Member] Georgia Power [Member]	Aug. 02, 2014 Subsequent Event [Member] Mississippi Power [Member]	Aug. 01, 2014 Subsequent Event [Member] Mississippi Power [Member]	Aug. 02, 2014 Subsequent Event [Member] Kemper IGCC [Member] Mississippi Power [Member]	Aug. 01, 2014 Subsequent Event [Member] Plant Watson Units 4 And 5 [Member] Mississippi Power [Member] MW	Aug. 01, 2014 Subsequent Event [Member] Plant Greene County Units 1 And 2 [Member] Mississippi Power [Member] MW	Aug. 01, 2014 Subsequent Event [Member] Plant Sweatt Units 1 And 2 [Member] Mississippi Power [Member] MW	Dec. 31, 2013 Non-Affiliate Capital Lease PPA [Member] Georgia Power [Member]	Jun. 30, 2014 Non-Affiliate Operating Lease PPA [Member] Georgia Power [Member]
Loss Contingencies [Line Items]
Projected Fuel Cost Over Or Under Recovery Threshold As Percentage Of Projected Fuel Revenue																					10.00%
Annual Retail Revenues																							$ 1,500,000
Number Of Wind PPAs							2
Number Of Wind Farms							2
Loss Contingency, Estimate of Possible Loss																											1,560,000,000		1,560,000,000
Environmental Matters
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
Environmental remediation liability								19,000,000		19,000,000									50,000,000		50,000,000						600,000		600,000
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
Damages awarded				17,000,000						27,000,000
Increase in base rate under cost based electric tariff due to settlement																								10,100,000
Revenue to be received from increase in base rate																											6,900,000		6,900,000
Retail Regulatory Matters
Under recovered rate CNP balance		33,000,000		33,000,000		18,000,000
Under recovered rate CNP environmental balance		32,000,000		32,000,000		7,000,000
Over Recovered Fuel Cost																															14,500,000
Under recovered regulatory clause revenues																			43,400,000		43,400,000						14,500,000		14,500,000
Accumulated reserve balance for future storms		87,000,000		87,000,000		96,000,000
Over recovered fuel cost balance																																																									244,000,000	58,000,000
Under Recovered Fuel Balance Threshold																	200,000,000
Period Of Inaction By The Public Service Commission For Fuel Rates										30 days
Regulatory Assets																																																											107,000,000	37,000,000
PSC Retail Rate Increase																																	3,600,000
Percentage Of PSC Retail Rate Increase																																	0.38%
Proportionate share owed in consortium agreement										45.70%
Increase In NCCR Tariff													60,000,000	50,000,000	35,000,000	223,000,000
Amortization to earnings of financing costs capitalized over the five year period								91,000,000		91,000,000
Amortization to earnings of financing costs capitalized, amortization term										5 years
Costs included in CWIP								27,000,000		27,000,000																	3,010,000,000		3,010,000,000
Increase (decrease) in projected certified construction capital costs										5.00%
Estimated In-service Capital Cost																	4,400,000,000	4,800,000,000
Cost incurred by Mississippi Power associated with plant including regulatory filing costs												2,000,000,000
Construction Capital Costs												400,000,000
Reduction in projected in-service cost due to recovered cost										425,000,000
Reduction In Depreciation Expense																					62,500,000
Reduction In Depreciation Expense Year One																					5,400,000
Psc Approved Annual Property Damage Reserve Accrual																																		3,300,000
Ownership percentage in scrubber project																			50.00%		50.00%						50.00%		50.00%
Estimated cost of scrubber project																											330,000,000		330,000,000									660,000,000
Scrubber project expenditures amount																											213,700,000		213,700,000									419,600,000
Allowance For Funds Used During Construction Cost																													13,300,000
Integrated Coal Gasification Combined Cycle [Abstract]
Estimated Cost																																										2,400,000,000							3,810,000,000	[1]		2,880,000,000
Period Rate Plan For Cost Accrued Through Additional Prudence Review																													7 years
Revisions To Revenue Requirement																											50,000,000		50,000,000
Alternate Financing																																									1,000,000,000
Revenue Requirement Obligations																																																						130,000,000	160,000,000
Costs associated with CCP12 grant funds																																245,300,000
Maximum Cap Construction Cost																																																	4,670,000,000	[1],[2]
Pre-tax charge to income																																											450,000,000	380,000,000	990,000,000	1,180,000,000	380,000,000				1,180,000,000
After tax charge to income																																											277,900,000	234,700,000	611,300,000	728,700,000	234,700,000				728,700,000
Costs Due To Extension Of In-service Date																													20,000,000
Costs included in CWIP								27,000,000		27,000,000																	3,010,000,000		3,010,000,000
Cost deferred in other regulatory assets																											97,100,000		97,100,000
Other deferred charges and assets																											3,900,000		3,900,000
Previously expensed																											1,100,000		1,100,000
Settlement Agreement To Increase Rates																																					172,000,000
Amortization Period For Construction Project																													40 years
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		156,000,000
Regulatory Liabilities																									172,400,000		74,300,000		74,300,000
Retail Revenues		1,249,000,000	1,221,000,000	2,546,000,000	2,362,000,000			2,000,000,000	1,879,000,000	4,050,000,000	3,608,000,000								310,344,000	305,550,000	613,464,000	565,427,000					211,326,000	214,254,000	418,364,000	382,564,000																		21,300,000	11,100,000
Reduced percentage interest transferred under asset purchase agreement																																15.00%
Term of Management Fee Contract																																																								40 years
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%
Deposit received																																150,000,000			75,000,000
Maximum period of discretion in the event senior unsecured credit rating falls																										15 days
Internal Revenue Code Section Forty Eight Tax Credits Phase I																													133,000,000
Internal Revenue Code Section Forty Eight Tax Credits Phase I I																													279,000,000
Minimum percentage of carbon dioxide that must be capture and sequester to remain eligible for the phase II tax credits																													65.00%
Tax Credit Carryforward, Amount																											276,400,000		276,400,000
Additional Bonus Depreciation For Property Acquired Future Periods																													50.00%
Positive Impact From Bonus Depreciation																																																	120,000,000
Electric Generating Units, Capacity																																							250	155													75											750	200	80
Capital Leases, Future Minimum Payments Due																																																																			641,000,000
Increase In Operating Leases Future Minimum Payments Due								127,000,000		127,000,000																																																										23,000,000
Operating Leases, Future Minimum Payments, Due in Two Years																																																																				116,000,000
Operating Leases, Future Minimum Payments, Due in Three Years																																																																				149,000,000
Operating Leases, Future Minimum Payments, Due in Four Years																																																																				150,000,000
Operating Leases, Future Minimum Payments, Due in Five Years																																																																				152,000,000
Operating Leases, Future Minimum Payments, Due Thereafter																																																																				1,700,000,000
Capacity Revenues Under Power Supply Agreement																															17,500,000
Number Of Regulatory Clauses																					4
Period Of Refraining From Intervening In Regulatory Proceedings																																																															3 years
Grant For Energy Efficiency And Renewable Program																																																														15,000,000
Period Of Grant For Energy Efficiency and Renewable Program																																																													5 years
Conservation Fund																																																														$ 2,000,000

[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.

[2] Amounts in the Current Estimate reflect costs through May 31, 2015, but do not reflect any adjustments as a result of the expected placement of the combined cycle and the associated common facilities portion of the Kemper IGCC in service in the summer of 2014.

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Fair Value Measurements - Assets and Liabilities Measured at Fair Value on a Recurring Basis (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2014
Fair Value, Measurements, Recurring [Member]
Assets:
Energy-related derivatives	$ 40
Nuclear decommissioning trusts	1,530	[1]
Cash equivalents	321
Other	13
Fair value assets, total	1,904
Liabilities:
Energy-related derivatives	36
Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member]
Assets:
Energy-related derivatives	0
Nuclear decommissioning trusts	651	[1]
Cash equivalents	321
Other	9
Fair value assets, total	981
Liabilities:
Energy-related derivatives	0
Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member]
Assets:
Energy-related derivatives	40
Nuclear decommissioning trusts	877	[1]
Cash equivalents	0
Other	0
Fair value assets, total	917
Liabilities:
Energy-related derivatives	36
Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member]
Assets:
Energy-related derivatives	0
Nuclear decommissioning trusts	2	[1]
Cash equivalents	0
Other	4
Fair value assets, total	6
Liabilities:
Energy-related derivatives	0
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member]
Assets:
Energy-related derivatives	14
Fair value assets, total	762
Liabilities:
Energy-related derivatives	5
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Domestic Equity [Member]
Assets:
Nuclear decommissioning trusts	489	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Foreign Equity [Member]
Assets:
Nuclear decommissioning trusts	104	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | U.S. Treasury and government agency securities [Member]
Assets:
Nuclear decommissioning trusts	33	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Corporate bonds [Member]
Assets:
Nuclear decommissioning trusts	95	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Mortgage and asset backed securities [Member]
Assets:
Nuclear decommissioning trusts	20	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Other investments [Member]
Assets:
Nuclear decommissioning trusts	7	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member]
Assets:
Energy-related derivatives	0
Fair value assets, total	444
Liabilities:
Energy-related derivatives	0
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Domestic Equity [Member]
Assets:
Nuclear decommissioning trusts	408	[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	0	[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:
Energy-related derivatives	14
Fair value assets, total	316
Liabilities:
Energy-related derivatives	5
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Domestic Equity [Member]
Assets:
Nuclear decommissioning trusts	81	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Foreign Equity [Member]
Assets:
Nuclear decommissioning trusts	68	[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	33	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Corporate bonds [Member]
Assets:
Nuclear decommissioning trusts	95	[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	20	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other investments [Member]
Assets:
Nuclear decommissioning trusts	5	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member]
Assets:
Energy-related derivatives	0
Fair value assets, total	2
Liabilities:
Energy-related derivatives	0
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Domestic Equity [Member]
Assets:
Nuclear decommissioning trusts	0	[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	2	[2]
Georgia Power [Member]
Assets:
Nuclear decommissioning trusts	49
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member]
Assets:
Energy-related derivatives	7
Fair value assets, total	789
Liabilities:
Energy-related derivatives	15
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Domestic Equity [Member]
Assets:
Nuclear decommissioning trusts	195	[2],[3]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Foreign Equity [Member]
Assets:
Nuclear decommissioning trusts	138	[2],[3]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | U.S. Treasury and government agency securities [Member]
Assets:
Nuclear decommissioning trusts	132	[2],[3]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Municipal bonds [Member]
Assets:
Nuclear decommissioning trusts	34	[2],[3]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Corporate bonds [Member]
Assets:
Nuclear decommissioning trusts	157	[2],[3]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Mortgage and asset backed securities [Member]
Assets:
Nuclear decommissioning trusts	108	[2],[3]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Other investments [Member]
Assets:
Nuclear decommissioning trusts	18	[2],[3]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member]
Assets:
Energy-related derivatives	0
Fair value assets, total	207
Liabilities:
Energy-related derivatives	0
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Domestic Equity [Member]
Assets:
Nuclear decommissioning trusts	194	[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	13	[2],[3]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member]
Assets:
Energy-related derivatives	7
Fair value assets, total	582
Liabilities:
Energy-related derivatives	15
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Domestic Equity [Member]
Assets:
Nuclear decommissioning trusts	1	[2],[3]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Foreign Equity [Member]
Assets:
Nuclear decommissioning trusts	138	[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	132	[2],[3]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Municipal bonds [Member]
Assets:
Nuclear decommissioning trusts	34	[2],[3]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Corporate bonds [Member]
Assets:
Nuclear decommissioning trusts	157	[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	108	[2],[3]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other investments [Member]
Assets:
Nuclear decommissioning trusts	5	[2],[3]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member]
Assets:
Energy-related derivatives	0
Fair value assets, total	0
Liabilities:
Energy-related derivatives	0
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Domestic Equity [Member]
Assets:
Nuclear decommissioning trusts	0	[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] | Fair Value, Measurements, Recurring [Member]
Assets:
Energy-related derivatives	12
Cash equivalents	18
Fair value assets, total	30
Liabilities:
Energy-related derivatives	11
Gulf Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member]
Assets:
Energy-related derivatives	0
Cash equivalents	18
Fair value assets, total	18
Liabilities:
Energy-related derivatives	0
Gulf Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member]
Assets:
Energy-related derivatives	12
Cash equivalents	0
Fair value assets, total	12
Liabilities:
Energy-related derivatives	11
Gulf Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member]
Assets:
Energy-related derivatives	0
Cash equivalents	0
Fair value assets, total	0
Liabilities:
Energy-related derivatives	0
Mississippi Power [Member] | Fair Value, Measurements, Recurring [Member]
Assets:
Energy-related derivatives	7
Cash equivalents	205
Fair value assets, total	212
Liabilities:
Energy-related derivatives	5
Mississippi Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member]
Assets:
Energy-related derivatives	0
Cash equivalents	205
Fair value assets, total	205
Liabilities:
Energy-related derivatives	0
Mississippi Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member]
Assets:
Energy-related derivatives	7
Cash equivalents	0
Fair value assets, total	7
Liabilities:
Energy-related derivatives	5
Mississippi Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member]
Assets:
Energy-related derivatives	0
Cash equivalents	0
Fair value assets, total	0
Liabilities:
Energy-related derivatives	0
Southern Power [Member] | Fair Value, Measurements, Recurring [Member]
Assets:
Cash equivalents	17
Fair value assets, total	17
Southern Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member]
Assets:
Cash equivalents	17
Fair value assets, total	17
Southern Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member]
Assets:
Cash equivalents	0
Fair value assets, total	0
Southern Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member]
Assets:
Cash equivalents	0
Fair value assets, total	$ 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, and payables related to pending investment purchases.

[3] Includes the investment securities pledged to creditors and cash collateral received and excludes payables related to the securities lending program. As of June 30, 2014, approximately $49 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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Condensed Consolidated Balance Sheets (Unaudited) - Parenthetical (USD $) In Thousands, except Share data, unless otherwise specified	Jun. 30, 2014	Dec. 31, 2013
Southern Company [Member]
Common stock, par value per share	$ 5	$ 5
Common stock, shares authorized	1,500,000,000	1,500,000,000
Common stock, shares issued	897,000,000	893,000,000
Treasury shares at cost	900,000	5,700,000
Alabama Power [Member]
Common stock, par value 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, 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	$ 0	$ 0
Common stock, shares authorized	20,000,000	20,000,000
Common stock, shares outstanding	5,442,717	4,942,717
Mississippi Power [Member]
Common stock, no par value	$ 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	$ 6,851	$ 5,614
Common stock, par value 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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Fair Value Measurements - Fair Value Measurements Calculated at Net Asset Value Per Share (Details) (USD $)	6 Months Ended
	Jun. 30, 2014
Foreign Equity [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	$ 138,000,000
Unfunded Commitments	0
Redemption Frequency	Monthly
Redemption Notice Period, Description	5 days
Foreign Equity [Member] | Georgia Power [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	138,000,000
Unfunded Commitments	0
Redemption Frequency	Monthly
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	68,000,000
Unfunded Commitments	0
Redemption Frequency	Daily/Monthly
Redemption Notice Period, Description	Daily/7 days
Equity - commingled funds [Member] | Alabama Power [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	68,000,000
Unfunded Commitments	0
Redemption Frequency	Daily/Monthly
Redemption Notice Period, Description	Daily/7 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	5,000,000
Unfunded Commitments	0
Redemption Frequency	Daily
Redemption Notice Period, Description	Not applicable
Other - commingled funds [Member] | Georgia Power [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	5,000,000
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	13,000,000
Unfunded Commitments	0
Redemption Frequency	Daily
Redemption Notice Period, Description	Not applicable
Other - money market funds [Member] | Georgia Power [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	13,000,000
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	114,000,000
Unfunded Commitments	0
Redemption Frequency	Daily
Redemption Notice Period, Description	15 days
Trust owned life insurance [Member] | Alabama Power [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	114,000,000
Unfunded Commitments	0
Redemption Frequency	Daily
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	321,000,000
Redemption Frequency	Daily
Redemption Notice Period, Description	Not applicable
Money market funds [Member] | Alabama Power [Member]
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments
Unfunded Commitments	0
Money market funds [Member] | Gulf Power [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
Money market funds [Member] | Mississippi Power [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	205,000,000
Unfunded Commitments	0
Redemption Frequency	Daily
Redemption Notice Period, Description	Not applicable
Money market funds [Member] | Southern Power [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	17,000,000
Unfunded Commitments	$ 0
Redemption Frequency	Daily
Redemption Notice Period, Description	Not applicable
Maximum [Member] | Foreign Equity [Member]
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments
Redemption Notice Period	5 days
Maximum [Member] | Foreign Equity [Member] | Georgia Power [Member]
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments
Redemption Notice Period	5 days
Maximum [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
Redemption Notice Period	7 days
Maximum [Member] | Equity - commingled funds [Member] | Alabama Power [Member]
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments
Redemption Notice Period	7 days
Maximum [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
Redemption Notice Period	7 days
Maximum [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
Redemption Notice Period	15 days
Maximum [Member] | Trust owned life insurance [Member] | Alabama Power [Member]
Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments
Redemption Notice Period	15 days

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Effective Tax Rate - Narrative (Details)	6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013
Effective Tax Rate and Unrecognized Tax Benefits (Textual) [Abstract]
Effective tax rate	33.30%	31.40%
Alabama Power [Member]
Effective Tax Rate and Unrecognized Tax Benefits (Textual) [Abstract]
Effective tax rate	39.30%	39.20%
Georgia Power [Member]
Effective Tax Rate and Unrecognized Tax Benefits (Textual) [Abstract]
Effective tax rate	37.00%	38.20%
Gulf Power [Member]
Effective Tax Rate and Unrecognized Tax Benefits (Textual) [Abstract]
Effective tax rate	37.30%	37.70%
Mississippi Power [Member]
Effective Tax Rate and Unrecognized Tax Benefits (Textual) [Abstract]
Effective tax rate	(51.10%)	(41.00%)
Southern Power [Member]
Effective Tax Rate and Unrecognized Tax Benefits (Textual) [Abstract]
Effective tax rate	0.30%	25.10%

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Condensed Consolidated Statements of Income (Unaudited) (USD $) Share data in Millions, except Per Share data, unless otherwise specified	3 Months Ended				6 Months Ended
	Jun. 30, 2014		Jun. 30, 2013		Jun. 30, 2014		Jun. 30, 2013
Operating Revenues:
Total operating revenues	$ 4,467,000,000		$ 4,246,000,000		$ 9,111,000,000		$ 8,143,000,000
Other Income and (Expense):
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries	611,000,000	[1],[2]	297,000,000	[1],[2]	962,000,000	[1],[3]	378,000,000	[1],[3]
Southern Company [Member]
Operating Revenues:
Retail revenues	3,770,000,000		3,620,000,000		7,628,000,000		6,918,000,000
Wholesale revenues	515,000,000		454,000,000		1,119,000,000		886,000,000
Other electric revenues	169,000,000		156,000,000		334,000,000		311,000,000
Other revenues	13,000,000		16,000,000		30,000,000		28,000,000
Total operating revenues	4,467,000,000		4,246,000,000		9,111,000,000		8,143,000,000
Operating Expenses:
Fuel	1,462,000,000		1,374,000,000		3,109,000,000		2,636,000,000
Purchased power	133,000,000		127,000,000		320,000,000		222,000,000
Other operations and maintenance	1,019,000,000		947,000,000		2,005,000,000		1,921,000,000
Depreciation and amortization	504,000,000		476,000,000		1,001,000,000		942,000,000
Taxes other than income taxes	246,000,000		232,000,000		493,000,000		467,000,000
Estimated loss on Kemper IGCC	0		450,000,000		380,000,000		990,000,000
Total operating expenses	3,364,000,000		3,606,000,000		7,308,000,000		7,178,000,000
Operating Income	1,103,000,000		640,000,000		1,803,000,000		965,000,000
Other Income and (Expense):
Allowance for equity funds used during construction	62,000,000		45,000,000		119,000,000		86,000,000
Interest expense, net of amounts capitalized	(210,000,000)		(215,000,000)		(416,000,000)		(426,000,000)
Other income (expense), net	(6,000,000)		1,000,000		(13,000,000)		(26,000,000)
Total other income and (expense)	(154,000,000)		(169,000,000)		(310,000,000)		(366,000,000)
Earnings Before Income Taxes	949,000,000		471,000,000		1,493,000,000		599,000,000
Income taxes	321,000,000		158,000,000		497,000,000		189,000,000
Consolidated Net Income	628,000,000		313,000,000		996,000,000		410,000,000
Less: Net income attributable to noncontrolling interest	17,000,000		16,000,000		34,000,000		32,000,000
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries	611,000,000		297,000,000		962,000,000		378,000,000
Earnings per share (EPS) -
Basic EPS (in dollars per share)	$ 0.68		$ 0.34		$ 1.08		$ 0.43
Diluted EPS (in dollars per share)	$ 0.68		$ 0.34		$ 1.07		$ 0.43
Average number of shares of common stock outstanding (in millions)
Basic (in shares)	895		874		892		872
Diluted (in shares)	899		879		896		877
Cash dividends paid per share of common stock	$ 0.5250		$ 0.5075		$ 1.0325		$ 0.9975
Alabama Power [Member]
Operating Revenues:
Retail revenues	1,249,000,000		1,221,000,000		2,546,000,000		2,362,000,000
Wholesale revenues, non-affiliates	65,000,000		61,000,000		150,000,000		120,000,000
Wholesale revenues, affiliates	68,000,000		60,000,000		137,000,000		116,000,000
Other revenues	55,000,000		50,000,000		112,000,000		102,000,000
Total operating revenues	1,437,000,000		1,392,000,000		2,945,000,000		2,700,000,000
Operating Expenses:
Fuel	414,000,000		401,000,000		846,000,000		773,000,000
Purchased power, non-affiliates	39,000,000		28,000,000		96,000,000		48,000,000
Purchased power, affiliates	37,000,000		41,000,000		86,000,000		72,000,000
Other operations and maintenance	330,000,000		319,000,000		655,000,000		649,000,000
Depreciation and amortization	172,000,000		159,000,000		347,000,000		317,000,000
Taxes other than income taxes	88,000,000		87,000,000		177,000,000		177,000,000
Total operating expenses	1,080,000,000		1,035,000,000		2,207,000,000		2,036,000,000
Operating Income	357,000,000		357,000,000		738,000,000		664,000,000
Other Income and (Expense):
Allowance for equity funds used during construction	11,000,000		8,000,000		21,000,000		16,000,000
Interest expense, net of amounts capitalized	(63,000,000)		(65,000,000)		(125,000,000)		(131,000,000)
Other income (expense), net	(3,000,000)		2,000,000		(8,000,000)		1,000,000
Total other income and (expense)	(55,000,000)		(55,000,000)		(112,000,000)		(114,000,000)
Earnings Before Income Taxes	302,000,000		302,000,000		626,000,000		550,000,000
Income taxes	119,000,000		119,000,000		246,000,000		216,000,000
Consolidated Net Income	183,000,000		183,000,000		380,000,000		334,000,000
Dividends on Preferred and Preference Stock	10,000,000		10,000,000		20,000,000		20,000,000
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries	173,000,000		173,000,000		360,000,000		314,000,000
Georgia Power [Member]
Operating Revenues:
Retail revenues	2,000,000,000		1,879,000,000		4,050,000,000		3,608,000,000
Wholesale revenues, non-affiliates	80,000,000		73,000,000		189,000,000		135,000,000
Wholesale revenues, affiliates	10,000,000		5,000,000		31,000,000		11,000,000
Other revenues	96,000,000		85,000,000		185,000,000		170,000,000
Total operating revenues	2,186,000,000		2,042,000,000		4,455,000,000		3,924,000,000
Operating Expenses:
Fuel	619,000,000		557,000,000		1,371,000,000		1,076,000,000
Purchased power, non-affiliates	63,000,000		61,000,000		142,000,000		111,000,000
Purchased power, affiliates	166,000,000		176,000,000		350,000,000		351,000,000
Other operations and maintenance	451,000,000		397,000,000		878,000,000		828,000,000
Depreciation and amortization	209,000,000		204,000,000		417,000,000		404,000,000
Taxes other than income taxes	106,000,000		95,000,000		209,000,000		190,000,000
Total operating expenses	1,614,000,000		1,490,000,000		3,367,000,000		2,960,000,000
Operating Income	572,000,000		552,000,000		1,088,000,000		964,000,000
Other Income and (Expense):
Allowance for equity funds used during construction	10,000,000		7,000,000		16,000,000		13,000,000
Interest expense, net of amounts capitalized	(90,000,000)		(96,000,000)		(174,000,000)		(187,000,000)
Other income (expense), net	1,000,000		1,000,000		(1,000,000)		(1,000,000)
Total other income and (expense)	(79,000,000)		(88,000,000)		(159,000,000)		(175,000,000)
Earnings Before Income Taxes	493,000,000		464,000,000		929,000,000		789,000,000
Income taxes	177,000,000		177,000,000		343,000,000		301,000,000
Consolidated Net Income	316,000,000		287,000,000		586,000,000		488,000,000
Dividends on Preferred and Preference Stock	5,000,000		5,000,000		9,000,000		9,000,000
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries	311,000,000		282,000,000		577,000,000		479,000,000
Gulf Power [Member]
Operating Revenues:
Retail revenues	310,344,000		305,550,000		613,464,000		565,427,000
Wholesale revenues, non-affiliates	34,335,000		31,894,000		69,927,000		53,102,000
Wholesale revenues, affiliates	23,627,000		19,050,000		76,405,000		48,505,000
Other revenues	15,225,000		14,679,000		30,867,000		30,413,000
Total operating revenues	383,531,000		371,173,000		790,663,000		697,447,000
Operating Expenses:
Fuel	145,244,000		140,347,000		313,666,000		261,193,000
Purchased power, non-affiliates	14,331,000		13,054,000		29,792,000		24,189,000
Purchased power, affiliates	9,184,000		10,934,000		15,688,000		14,246,000
Other operations and maintenance	81,127,000		76,846,000		165,328,000		155,508,000
Depreciation and amortization	39,010,000		37,081,000		70,867,000		74,134,000
Taxes other than income taxes	25,758,000		23,760,000		52,557,000		47,386,000
Total operating expenses	314,654,000		302,022,000		647,898,000		576,656,000
Operating Income	68,877,000		69,151,000		142,765,000		120,791,000
Other Income and (Expense):
Allowance for equity funds used during construction	2,702,000		1,521,000		5,081,000		2,655,000
Interest expense, net of amounts capitalized	(13,294,000)		(14,293,000)		(26,558,000)		(28,662,000)
Other income (expense), net	(505,000)		(1,391,000)		(1,230,000)		(2,367,000)
Total other income and (expense)	(11,097,000)		(14,163,000)		(22,707,000)		(28,374,000)
Earnings Before Income Taxes	57,780,000		54,988,000		120,058,000		92,417,000
Income taxes	21,433,000		20,755,000		44,717,000		34,841,000
Consolidated Net Income	36,347,000		34,233,000		75,341,000		57,576,000
Dividends on Preferred and Preference Stock	2,250,000		1,651,000		4,501,000		3,202,000
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries	34,097,000		32,582,000		70,840,000		54,374,000
Mississippi Power [Member]
Operating Revenues:
Retail revenues	211,326,000		214,254,000		418,364,000		382,564,000
Wholesale revenues, non-affiliates	74,972,000		71,938,000		171,690,000		137,047,000
Wholesale revenues, affiliates	20,165,000		15,902,000		42,954,000		24,243,000
Other revenues	4,512,000		4,341,000		9,128,000		8,515,000
Total operating revenues	310,975,000		306,435,000		642,136,000		552,369,000
Operating Expenses:
Fuel	143,317,000		142,193,000		290,268,000		246,757,000
Purchased power, non-affiliates	1,194,000		1,778,000		12,688,000		3,145,000
Purchased power, affiliates	5,735,000		3,922,000		14,664,000		13,611,000
Other operations and maintenance	60,070,000		54,456,000		126,165,000		109,268,000
Depreciation and amortization	24,242,000		22,209,000		46,936,000		45,442,000
Taxes other than income taxes	20,396,000		20,272,000		40,854,000		39,689,000
Estimated loss on Kemper IGCC	0		450,000,000		380,000,000		912,000,000
Total operating expenses	254,954,000		694,830,000		911,575,000		1,369,912,000
Operating Income	56,021,000		(388,395,000)		(269,439,000)		(817,543,000)
Other Income and (Expense):
Allowance for equity funds used during construction	37,380,000		29,042,000		75,462,000		55,116,000
Interest expense, net of amounts capitalized	(12,620,000)		(10,389,000)		(24,655,000)		(20,798,000)
Other income (expense), net	(1,933,000)		(2,262,000)		(3,732,000)		(3,809,000)
Total other income and (expense)	22,827,000		16,391,000		47,075,000		30,509,000
Earnings Before Income Taxes	78,848,000		(372,004,000)		(222,364,000)		(787,034,000)
Income taxes	15,920,000		(153,327,000)		(113,677,000)		(322,469,000)
Consolidated Net Income	62,928,000		(218,677,000)		(108,687,000)		(464,565,000)
Dividends on Preferred and Preference Stock	433,000		433,000		866,000		866,000
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries	62,495,000		(219,110,000)		(109,553,000)		(465,431,000)
Southern Power [Member]
Operating Revenues:
Wholesale revenues, non-affiliates	260,347,000		216,647,000		538,215,000		440,076,000
Wholesale revenues, affiliates	67,563,000		88,638,000		139,896,000		166,829,000
Other revenues	893,000		1,970,000		1,546,000		3,297,000
Total operating revenues	328,803,000		307,255,000		679,657,000		610,202,000
Operating Expenses:
Fuel	118,053,000		110,630,000		242,615,000		230,002,000
Purchased power, non-affiliates	16,594,000		22,307,000		44,487,000		36,880,000
Purchased power, affiliates	16,493,000		6,282,000		45,679,000		14,147,000
Other operations and maintenance	69,330,000		62,661,000		122,045,000		113,611,000
Depreciation and amortization	51,559,000		44,898,000		103,016,000		85,058,000
Taxes other than income taxes	5,701,000		5,453,000		11,384,000		10,807,000
Total operating expenses	277,730,000		252,231,000		569,226,000		490,505,000
Operating Income	51,073,000		55,024,000		110,431,000		119,697,000
Other Income and (Expense):
Interest expense, net of amounts capitalized	(21,966,000)		(20,568,000)		(43,969,000)		(40,962,000)
Other income (expense), net	(32,000)		(1,691,000)		85,000		(1,948,000)
Total other income and (expense)	(21,998,000)		(22,259,000)		(43,884,000)		(42,910,000)
Earnings Before Income Taxes	29,075,000		32,765,000		66,547,000		76,787,000
Income taxes	(2,969,000)		4,843,000		217,000		19,673,000
Consolidated Net Income	32,044,000		27,922,000		66,330,000		57,114,000
Less: Net income attributable to noncontrolling interest	1,232,000		0		2,047,000		0
Average number of shares of common stock outstanding (in millions)
Net income attributable to Southern Power Company	$ 30,812,000		$ 27,922,000		$ 64,283,000		$ 57,114,000

[1] After dividends on preferred and preference stock of subsidiaries.

[2] Segment net income (loss) for the traditional operating companies for the three months ended June 30, 2013 includes a $450.0 million pre-tax charge ($277.9 million after tax) for an estimated probable loss on the Kemper IGCC. See Note (B) under "Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" herein for additional information.

[3] Segment net income (loss) for the traditional operating companies for the six months ended June 30, 2014 and June 30, 2013 includes $380.0 million in pre-tax charges ($234.7 million after tax) and $990.0 million in pre-tax charges ($611.3 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.

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Derivatives - Narrative (Details)	6 Months Ended
	Jun. 30, 2014 MMBTU
Southern Company [Member]
Derivatives (Textual) [Abstract]
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints	8,000,000
Alabama 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
Georgia Power [Member]
Derivatives (Textual) [Abstract]
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints	5,000,000
Gulf 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
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
Agreement Through Two Thousand Fifteen [Member] | Gulf Power [Member]
Derivative [Line Items]
Wholesale Capacity Percentage	100.00%
Agreement Through Two Thousand Nineteen [Member] | Gulf Power [Member]
Derivative [Line Items]
Wholesale Capacity Percentage	57.00%

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Condensed Consolidated Statements of Cash Flows (Unaudited) (Parenthetical) (USD $) In Thousands, unless otherwise specified	6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013
Net cash paid for capitalized interest	$ 47,000	$ 37,000
Alabama Power [Member]
Net cash paid for capitalized interest	8,000	6,000
Georgia Power [Member]
Net cash paid for capitalized interest	8,000	6,000
Gulf Power [Member]
Net cash paid for capitalized interest	2,271	1,408
Mississippi Power [Member]
Interest paid	37,436	37,036
Net cash paid for capitalized interest	29,087	23,613
Southern Power [Member]
Net cash paid for capitalized interest	$ (113)	$ 0

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Stockholders' Equity - Earnings per Share (Details) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Earnings per Share
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	8		17
Southern Company [Member]
Earnings per Share
As reported shares	895	874	892	872
Effect of options and performance share award units	4	5	4	5
Diluted shares	899	879	896	877

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Stockholders' Equity (Tables)

6 Months Ended

Jun. 30, 2014

Equity [Abstract]

Earnings per Share

Shares used to compute diluted earnings per share were as follows:

	Three Months Ended June 30, 2014	Three Months Ended June 30, 2013	Six Months Ended June 30, 2014	Six Months Ended June 30, 2013
	(in millions)
As reported shares	895	874	892	872
Effect of options and performance share award units	4	5	4	5
Diluted shares	899	879	896	877

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
	(in thousands)						(in millions)
Balance at December 31, 2013	892,733	(5,647	)	$	19,008		$	756	$	19,764
Net income after dividends on preferred and preference stock	—	—		962			—		962
Other comprehensive income (loss)	—	—		4			—		4
Treasury stock re-issued	—	4,739		216			—		216
Stock issued	3,898	—		161			—		161
Stock repurchased, at cost	—	—		(5		)	—		(5		)
Cash dividends on common stock	—	—		(920		)	—		(920		)
Other	—	(27	)	—			—		—
Balance at June 30, 2014	896,631	(935	)	$	19,426		$	756	$	20,182
Balance at December 31, 2012	877,803	(10,035	)	$	18,297		$	707	$	19,004
Net income after dividends on preferred and preference stock	—	—		378			—		378
Other comprehensive income (loss)	—	—		9			—		9
Stock issued	6,144	—		244			49		293
Stock repurchased, at cost	—	—		(18		)	—		(18		)
Cash dividends on common stock	—	—		(870		)	—		(870		)
Other	—	(9	)	—			—		—
Balance at June 30, 2013	883,947	(10,044	)	$	18,040		$	756	$	18,796

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Stockholders' Equity - Changes in Stockholders' Equity (Details) (USD $) Share data in Thousands, unless otherwise specified	3 Months Ended				6 Months Ended
	Jun. 30, 2014		Jun. 30, 2013		Jun. 30, 2014		Jun. 30, 2013
Changes in Stockholders' Equity
Beginning Balance					$ 19,764,000,000		$ 19,004,000,000
Net Income After Dividends on Preferred and Preference Stock	611,000,000	[1],[2]	297,000,000	[1],[2]	962,000,000	[1],[3]	378,000,000	[1],[3]
Other comprehensive income (loss)					4,000,000		9,000,000
Stock Issued During Period, Value, Treasury Stock Reissued					216,000,000
Stock issued					161,000,000		293,000,000
Stock Repurchased During Period, Value					(5,000,000)		(18,000,000)
Cash dividends on common stock					(920,000,000)		(870,000,000)
Other					0		0
Ending Balance	20,182,000,000		18,796,000,000		20,182,000,000		18,796,000,000
Number of Common shares Issued [Member]
Changes in Stockholders' Equity
Beginning Balance, Shares					892,733		877,803
Stock issued, shares					3,898		6,144
Stock Repurchased During Period, Shares					0		0
Ending Balance, Shares	896,631		883,947		896,631		883,947
Number of Common shares Treasury [Member]
Changes in Stockholders' Equity
Beginning Balance, Shares					5,647		10,035
Stock Issued During Period, Shares, Treasury Stock Reissued					4,739
Stock Repurchased During Period, Shares					0		0
Other, Shares					(27)		(9)
Ending Balance, Shares	935		10,044		935		10,044
Common Stockholders' Equity [Member]
Changes in Stockholders' Equity
Beginning Balance					19,008,000,000		18,297,000,000
Net Income After Dividends on Preferred and Preference Stock					962,000,000		378,000,000
Other comprehensive income (loss)					4,000,000		9,000,000
Stock Issued During Period, Value, Treasury Stock Reissued					216,000,000
Stock issued					161,000,000		244,000,000
Stock Repurchased During Period, Value					(5,000,000)		(18,000,000)
Cash dividends on common stock					(920,000,000)		(870,000,000)
Other					0		0
Ending Balance	19,426,000,000		18,040,000,000		19,426,000,000		18,040,000,000
Preferred and Preference Stock of Subsidiaries [Member]
Changes in Stockholders' Equity
Beginning Balance					756,000,000		707,000,000
Net Income After Dividends on Preferred and Preference Stock					0		0
Other comprehensive income (loss)					0		0
Stock Issued During Period, Value, Treasury Stock Reissued					0
Stock issued					0		49,000,000
Stock Repurchased During Period, Value					0		0
Cash dividends on common stock					0		0
Other					0		0
Ending Balance	$ 756,000,000		$ 756,000,000		$ 756,000,000		$ 756,000,000

[1] After dividends on preferred and preference stock of subsidiaries.

[2] Segment net income (loss) for the traditional operating companies for the three months ended June 30, 2013 includes a $450.0 million pre-tax charge ($277.9 million after tax) for an estimated probable loss on the Kemper IGCC. See Note (B) under "Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" herein for additional information.

[3] Segment net income (loss) for the traditional operating companies for the six months ended June 30, 2014 and June 30, 2013 includes $380.0 million in pre-tax charges ($234.7 million after tax) and $990.0 million in pre-tax charges ($611.3 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.

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Retirement Benefits (Tables)

6 Months Ended

Jun. 30, 2014

Compensation and Retirement Disclosure [Abstract]

Pension Plans and Postretirement Plans

Components of the net periodic benefit costs for the three and six months ended June 30, 2014 and 2013 were as follows:

Pension Plans	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power
	(in millions)
Three Months Ended June 30, 2014
Service cost	$	54		$	12		$	15		$	1		$	2
Interest cost	108			26			38			5			5
Expected return on plan assets	(162		)	(42		)	(56		)	(7		)	(7		)
Amortization:
Prior service costs	7			2			2			1			1
Net (gain)/loss	27			8			10			1			1
Net cost	$	34		$	6		$	9		$	1		$	2
Six Months Ended June 30, 2014
Service cost	$	107		$	24		$	31		$	4		$	5
Interest cost	217			52			76			10			10
Expected return on plan assets	(323		)	(84		)	(113		)	(14		)	(14		)
Amortization:
Prior service costs	13			3			5			1			1
Net (gain)/loss	55			16			20			2			2
Net cost	$	69		$	11		$	19		$	3		$	4
Three Months Ended June 30, 2013
Service cost	$	58		$	14		$	18		$	2		$	2
Interest cost	97			23			35			5			4
Expected return on plan assets	(150		)	(39		)	(53		)	(7		)	(6		)
Amortization:
Prior service costs	6			1			2			1			—
Net (gain)/loss	50			13			18			2			3
Net cost	$	61		$	12		$	20		$	3		$	3
Six Months Ended June 30, 2013
Service cost	$	116		$	27		$	35		$	5		$	5
Interest cost	194			46			69			9			9
Expected return on plan assets	(301		)	(78		)	(106		)	(13		)	(13		)
Amortization:
Prior service costs	13			3			5			1			—
Net (gain)/loss	100			26			37			4			5
Net cost	$	122		$	24		$	40		$	6		$	6

Postretirement Benefits	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power
	(in millions)
Three Months Ended June 30, 2014
Service cost	$	6		$	2		$	1		$	1		$	1
Interest cost	20			5			9			1			1
Expected return on plan assets	(15		)	(7		)	(7		)	(1		)	(1		)
Amortization:
Prior service costs	1			1			—			—			—
Net (gain)/loss	—			—			1			—			—
Net cost	$	12		$	1		$	4		$	1		$	1
Six Months Ended June 30, 2014
Service cost	$	11		$	3		$	3		$	1		$	1
Interest cost	40			10			17			2			2
Expected return on plan assets	(30		)	(13		)	(13		)	(1		)	(1		)
Amortization:
Prior service costs	2			2			—			—			—
Net (gain)/loss	1			—			1			—			—
Net cost	$	24		$	2		$	8		$	2		$	2
Three Months Ended June 30, 2013
Service cost	$	6		$	1		$	1		$	1		$	1
Interest cost	18			4			8			—			1
Expected return on plan assets	(14		)	(6		)	(6		)	—			(1		)
Amortization:
Transition obligation	1			—			1			—			—
Prior service costs	1			1			—			—			—
Net (gain)/loss	3			1			2			—			—
Net cost	$	15		$	1		$	6		$	1		$	1
Six Months Ended June 30, 2013
Service cost	$	12		$	3		$	3		$	1		$	1
Interest cost	37			9			16			1			2
Expected return on plan assets	(28		)	(12		)	(12		)	—			(1		)
Amortization:
Transition obligation	2			—			2			—			—
Prior service costs	2			2			—			—			—
Net (gain)/loss	6			1			4			—			—
Net cost	$	31		$	3		$	13		$	2		$	2

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Condensed Consolidated Balance Sheets (Unaudited) (USD $)	Jun. 30, 2014	Dec. 31, 2013
Deferred Charges and Other Assets:
Total Assets	$ 66,400,000,000	$ 64,546,000,000
Common Stockholders' Equity:
Total Stockholders' Equity	20,182,000,000	19,764,000,000
Southern Company [Member]
Current Assets:
Cash and cash equivalents	583,000,000	659,000,000
Receivables --
Customer accounts receivable	1,237,000,000	1,027,000,000
Unbilled revenues	532,000,000	448,000,000
Under recovered regulatory clause revenues	86,000,000	58,000,000
Other accounts and notes receivable	281,000,000	304,000,000
Accumulated provision for uncollectible accounts	(17,000,000)	(18,000,000)
Fossil fuel stock, at average cost	920,000,000	1,339,000,000
Materials and supplies, at average cost	981,000,000	959,000,000
Vacation pay	171,000,000	171,000,000
Prepaid expenses	422,000,000	489,000,000
Other regulatory assets, current	117,000,000	124,000,000
Other current assets	63,000,000	39,000,000
Total current assets	5,376,000,000	5,599,000,000
Property, Plant, and Equipment:
In service	67,235,000,000	66,021,000,000
Less accumulated provision for depreciation	23,492,000,000	23,059,000,000
Plant in service, net of depreciation	43,743,000,000	42,962,000,000
Other utility plant, net	226,000,000	240,000,000
Nuclear fuel, at amortized cost	868,000,000	855,000,000
Construction work in progress	7,927,000,000	7,151,000,000
Total property, plant, and equipment	52,764,000,000	51,208,000,000
Other Property and Investments:
Nuclear decommissioning trusts, at fair value	1,531,000,000	1,465,000,000
Leveraged leases	675,000,000	665,000,000
Miscellaneous property and investments	230,000,000	218,000,000
Total other property and investments	2,436,000,000	2,348,000,000
Deferred Charges and Other Assets:
Deferred charges related to income taxes	1,467,000,000	1,432,000,000
Prepaid pension costs	431,000,000	419,000,000
Unamortized debt issuance expense	200,000,000	139,000,000
Unamortized loss on reacquired debt	281,000,000	293,000,000
Other regulatory assets, deferred	2,642,000,000	2,557,000,000
Other deferred charges and assets	803,000,000	551,000,000
Total deferred charges and other assets	5,824,000,000	5,391,000,000
Total Assets	66,400,000,000	64,546,000,000
Current Liabilities:
Securities due within one year	585,000,000	469,000,000
Interest-bearing refundable deposit related to asset sale	225,000,000	150,000,000
Notes payable	1,817,000,000	1,482,000,000
Accounts Payable and Accrued Liabilities, Current [Abstract]
Other accounts payable	1,320,000,000	1,376,000,000
Customer deposits	386,000,000	380,000,000
Accrued taxes --
Accrued income taxes	58,000,000	13,000,000
Other accrued taxes	391,000,000	456,000,000
Accrued interest	268,000,000	251,000,000
Accrued vacation pay	213,000,000	217,000,000
Accrued compensation	282,000,000	303,000,000
Other regulatory liabilities, current	92,000,000	92,000,000
Other current liabilities	337,000,000	347,000,000
Total current liabilities	5,974,000,000	5,536,000,000
Long-term Debt	22,121,000,000	21,344,000,000
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	10,644,000,000	10,563,000,000
Deferred credits related to income taxes	194,000,000	202,000,000
Accumulated deferred investment tax credits	1,014,000,000	966,000,000
Employee benefit obligations	1,428,000,000	1,461,000,000
Asset retirement obligations	2,026,000,000	2,006,000,000
Other cost of removal obligations	1,332,000,000	1,270,000,000
Other regulatory liabilities, deferred	537,000,000	475,000,000
Other deferred credits and liabilities	573,000,000	584,000,000
Total deferred credits and other liabilities	17,748,000,000	17,527,000,000
Total Liabilities	45,843,000,000	44,407,000,000
Redeemable Preferred Stock of Subsidiaries	375,000,000	375,000,000
Common Stockholders' Equity:
Common stock	4,480,000,000	4,461,000,000
Paid-in capital	5,499,000,000	5,362,000,000
Treasury, at cost	(35,000,000)	(250,000,000)
Retained earnings	9,553,000,000	9,510,000,000
Accumulated other comprehensive loss	(71,000,000)	(75,000,000)
Total common stockholders' equity	19,426,000,000	19,008,000,000
Preferred and Preference Stock of Subsidiaries	756,000,000	756,000,000
Total Stockholders' Equity	20,182,000,000	19,764,000,000
Total Liabilities and Stockholders' Equity	66,400,000,000	64,546,000,000
Alabama Power [Member]
Current Assets:
Cash and cash equivalents	105,000,000	295,000,000
Receivables --
Customer accounts receivable	391,000,000	341,000,000
Unbilled revenues	156,000,000	142,000,000
Other accounts and notes receivable	39,000,000	30,000,000
Affiliated companies	62,000,000	54,000,000
Accumulated provision for uncollectible accounts	(9,000,000)	(8,000,000)
Fossil fuel stock, at average cost	235,000,000	329,000,000
Materials and supplies, at average cost	377,000,000	375,000,000
Vacation pay	63,000,000	63,000,000
Prepaid expenses	119,000,000	57,000,000
Other regulatory assets, current	4,000,000	7,000,000
Other current assets	16,000,000	6,000,000
Total current assets	1,558,000,000	1,691,000,000
Property, Plant, and Equipment:
In service	22,533,000,000	22,092,000,000
Less accumulated provision for depreciation	8,315,000,000	8,114,000,000
Plant in service, net of depreciation	14,218,000,000	13,978,000,000
Nuclear fuel, at amortized cost	348,000,000	332,000,000
Construction work in progress	808,000,000	748,000,000
Total property, plant, and equipment	15,374,000,000	15,058,000,000
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	57,000,000	54,000,000
Nuclear decommissioning trusts, at fair value	749,000,000	714,000,000
Miscellaneous property and investments	82,000,000	80,000,000
Total other property and investments	888,000,000	848,000,000
Deferred Charges and Other Assets:
Deferred charges related to income taxes	525,000,000	519,000,000
Prepaid pension costs	284,000,000	276,000,000
Deferred under recovered regulatory clause revenues	65,000,000	25,000,000
Other regulatory assets, deferred	702,000,000	692,000,000
Other deferred charges and assets	134,000,000	142,000,000
Total deferred charges and other assets	1,710,000,000	1,654,000,000
Total Assets	19,530,000,000	19,251,000,000
Current Liabilities:
Securities due within one year	54,000,000	0
Notes payable	27,000,000	0
Accounts Payable and Accrued Liabilities, Current [Abstract]
Affiliated accounts payable	193,000,000	198,000,000
Other accounts payable	327,000,000	339,000,000
Customer deposits	86,000,000	85,000,000
Accrued taxes --
Accrued income taxes	67,000,000	11,000,000
Other accrued taxes	85,000,000	33,000,000
Accrued interest	64,000,000	61,000,000
Accrued vacation pay	53,000,000	53,000,000
Accrued compensation	62,000,000	74,000,000
Other regulatory liabilities, current	33,000,000	37,000,000
Other current liabilities	40,000,000	41,000,000
Total current liabilities	1,091,000,000	932,000,000
Long-term Debt	6,180,000,000	6,233,000,000
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	3,646,000,000	3,603,000,000
Deferred credits related to income taxes	73,000,000	75,000,000
Accumulated deferred investment tax credits	129,000,000	133,000,000
Employee benefit obligations	186,000,000	195,000,000
Asset retirement obligations	751,000,000	730,000,000
Other cost of removal obligations	856,000,000	828,000,000
Other regulatory liabilities, deferred	260,000,000	259,000,000
Deferred Over Recovered Regulatory Clause Revenues	0	15,000,000
Other deferred credits and liabilities	65,000,000	61,000,000
Total deferred credits and other liabilities	5,966,000,000	5,899,000,000
Total Liabilities	13,237,000,000	13,064,000,000
Redeemable Preferred Stock	342,000,000	342,000,000
Preference Stock	343,000,000	343,000,000
Common Stockholders' Equity:
Common stock	1,222,000,000	1,222,000,000
Paid-in capital	2,281,000,000	2,262,000,000
Retained earnings	2,130,000,000	2,044,000,000
Accumulated other comprehensive loss	(25,000,000)	(26,000,000)
Total common stockholders' equity	5,608,000,000	5,502,000,000
Total Liabilities and Stockholders' Equity	19,530,000,000	19,251,000,000
Georgia Power [Member]
Current Assets:
Cash and cash equivalents	46,000,000	30,000,000
Receivables --
Customer accounts receivable	609,000,000	512,000,000
Unbilled revenues	260,000,000	209,000,000
Joint owner accounts receivable	76,000,000	67,000,000
Other accounts and notes receivable	75,000,000	117,000,000
Affiliated companies	19,000,000	21,000,000
Accumulated provision for uncollectible accounts	(6,000,000)	(5,000,000)
Fossil fuel stock, at average cost	487,000,000	742,000,000
Materials and supplies, at average cost	417,000,000	409,000,000
Vacation pay	88,000,000	88,000,000
Prepaid income taxes	85,000,000	97,000,000
Other regulatory assets, current	61,000,000	66,000,000
Other current assets	82,000,000	54,000,000
Total current assets	2,299,000,000	2,407,000,000
Property, Plant, and Equipment:
In service	30,545,000,000	30,132,000,000
Less accumulated provision for depreciation	11,056,000,000	10,970,000,000
Plant in service, net of depreciation	19,489,000,000	19,162,000,000
Other utility plant, net	226,000,000	240,000,000
Nuclear fuel, at amortized cost	519,000,000	523,000,000
Construction work in progress	3,737,000,000	3,500,000,000
Total property, plant, and equipment	23,971,000,000	23,425,000,000
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	49,000,000	46,000,000
Nuclear decommissioning trusts, at fair value	782,000,000	751,000,000
Miscellaneous property and investments	43,000,000	44,000,000
Total other property and investments	874,000,000	841,000,000
Deferred Charges and Other Assets:
Deferred charges related to income taxes	705,000,000	718,000,000
Prepaid pension costs	128,000,000	118,000,000
Deferred under recovered regulatory clause revenues	244,000,000	0
Other regulatory assets, deferred	1,164,000,000	1,152,000,000
Other deferred charges and assets	284,000,000	246,000,000
Total deferred charges and other assets	2,525,000,000	2,234,000,000
Total Assets	29,669,000,000	28,907,000,000
Current Liabilities:
Securities due within one year	5,000,000	5,000,000
Notes payable	689,000,000	1,047,000,000
Accounts Payable and Accrued Liabilities, Current [Abstract]
Affiliated accounts payable	444,000,000	417,000,000
Other accounts payable	437,000,000	472,000,000
Customer deposits	251,000,000	246,000,000
Accrued taxes --
Accrued income taxes	38,000,000	0
Other accrued taxes	215,000,000	321,000,000
Accrued interest	96,000,000	91,000,000
Accrued vacation pay	60,000,000	61,000,000
Accrued compensation	75,000,000	80,000,000
Liabilities from risk management activities	11,000,000	13,000,000
Nuclear decommissioning trust securities lending collateral	14,000,000	9,000,000
Other regulatory liabilities, current	21,000,000	17,000,000
Other current liabilities	148,000,000	127,000,000
Total current liabilities	2,504,000,000	2,906,000,000
Long-term Debt	9,594,000,000	8,633,000,000
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	5,297,000,000	5,200,000,000
Deferred credits related to income taxes	109,000,000	112,000,000
Accumulated deferred investment tax credits	198,000,000	203,000,000
Employee benefit obligations	539,000,000	542,000,000
Asset retirement obligations	1,205,000,000	1,210,000,000
Other cost of removal obligations	64,000,000	43,000,000
Other deferred credits and liabilities	171,000,000	201,000,000
Total deferred credits and other liabilities	7,583,000,000	7,511,000,000
Total Liabilities	19,681,000,000	19,050,000,000
Redeemable Preferred Stock	45,000,000	45,000,000
Preference Stock	221,000,000	221,000,000
Common Stockholders' Equity:
Common stock	398,000,000	398,000,000
Paid-in capital	5,665,000,000	5,633,000,000
Retained earnings	3,663,000,000	3,565,000,000
Accumulated other comprehensive loss	(4,000,000)	(5,000,000)
Total common stockholders' equity	9,722,000,000	9,591,000,000
Total Liabilities and Stockholders' Equity	29,669,000,000	28,907,000,000
Gulf Power [Member]
Current Assets:
Cash and cash equivalents	29,700,000	21,753,000
Receivables --
Customer accounts receivable	83,332,000	64,884,000
Unbilled revenues	72,613,000	57,282,000
Under recovered regulatory clause revenues	66,343,000	48,282,000
Other accounts and notes receivable	11,814,000	8,620,000
Affiliated companies	10,600,000	8,259,000
Accumulated provision for uncollectible accounts	(1,295,000)	(1,131,000)
Fossil fuel stock, at average cost	95,864,000	135,050,000
Materials and supplies, at average cost	53,766,000	54,935,000
Prepaid expenses	9,890,000	33,186,000
Other regulatory assets, current	16,567,000	18,536,000
Other current assets	9,680,000	6,120,000
Total current assets	458,874,000	455,776,000
Property, Plant, and Equipment:
In service	4,434,802,000	4,363,664,000
Less accumulated provision for depreciation	1,252,856,000	1,211,336,000
Plant in service, net of depreciation	3,181,946,000	3,152,328,000
Construction work in progress	352,194,000	280,626,000
Total property, plant, and equipment	3,534,140,000	3,432,954,000
Other Property and Investments:
Total other property and investments	15,169,000	15,314,000
Deferred Charges and Other Assets:
Deferred charges related to income taxes	53,436,000	50,597,000
Prepaid pension costs	11,604,000	11,533,000
Other regulatory assets, deferred	347,665,000	340,415,000
Other deferred charges and assets	41,492,000	30,982,000
Total deferred charges and other assets	454,197,000	433,527,000
Total Assets	4,462,380,000	4,337,571,000
Current Liabilities:
Securities due within one year	75,000,000	75,000,000
Notes payable	138,580,000	135,878,000
Accounts Payable and Accrued Liabilities, Current [Abstract]
Affiliated accounts payable	78,005,000	76,897,000
Other accounts payable	46,166,000	47,038,000
Customer deposits	34,849,000	34,433,000
Accrued taxes --
Accrued income taxes	45,000	45,000
Other accrued taxes	21,525,000	7,486,000
Accrued interest	8,490,000	10,272,000
Accrued compensation	11,549,000	11,657,000
Liabilities from risk management activities	3,707,000	6,470,000
Other regulatory liabilities, current	17,709,000	13,408,000
Other current liabilities	21,173,000	22,972,000
Total current liabilities	456,798,000	441,556,000
Long-term Debt	1,171,446,000	1,158,163,000
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	751,131,000	734,355,000
Accumulated deferred investment tax credits	3,419,000	4,055,000
Employee benefit obligations	76,504,000	76,338,000
Other cost of removal obligations	230,344,000	228,148,000
Other regulatory liabilities, deferred	57,117,000	56,051,000
Deferred capacity expense	196,059,000	180,149,000
Other deferred credits and liabilities	74,590,000	77,126,000
Total deferred credits and other liabilities	1,389,164,000	1,356,222,000
Total Liabilities	3,017,408,000	2,955,941,000
Preference Stock	146,504,000	146,504,000
Common Stockholders' Equity:
Common stock	483,060,000	433,060,000
Paid-in capital	556,596,000	552,681,000
Retained earnings	259,735,000	250,494,000
Accumulated other comprehensive loss	(923,000)	(1,109,000)
Total common stockholders' equity	1,298,468,000	1,235,126,000
Total Liabilities and Stockholders' Equity	4,462,380,000	4,337,571,000
Mississippi Power [Member]
Current Assets:
Cash and cash equivalents	245,891,000	145,165,000
Receivables --
Customer accounts receivable	43,988,000	40,978,000
Unbilled revenues	43,271,000	38,895,000
Under recovered regulatory clause revenues	19,842,000	0
Other accounts and notes receivable	2,646,000	4,600,000
Affiliated companies	41,460,000	34,920,000
Accumulated provision for uncollectible accounts	(1,193,000)	(3,018,000)
Fossil fuel stock, at average cost	81,578,000	113,285,000
Materials and supplies, at average cost	50,954,000	45,347,000
Prepaid income taxes	14,989,000	34,751,000
Other regulatory assets, current	54,629,000	52,496,000
Other current assets	9,492,000	9,357,000
Total current assets	607,547,000	516,776,000
Property, Plant, and Equipment:
In service	3,492,473,000	3,458,770,000
Less accumulated provision for depreciation	1,128,231,000	1,095,352,000
Plant in service, net of depreciation	2,364,242,000	2,363,418,000
Construction work in progress	2,925,736,000	2,586,031,000
Total property, plant, and equipment	5,289,978,000	4,949,449,000
Other Property and Investments:
Total other property and investments	5,026,000	4,857,000
Deferred Charges and Other Assets:
Deferred charges related to income taxes	177,865,000	139,834,000
Other regulatory assets, deferred	220,994,000	200,620,000
Accumulated deferred income taxes	16,025,000	0
Other deferred charges and assets	47,548,000	36,673,000
Total deferred charges and other assets	462,432,000	377,127,000
Total Assets	6,364,983,000	5,848,209,000
Current Liabilities:
Securities due within one year	426,170,000	13,789,000
Interest-bearing refundable deposit related to asset sale	225,000,000	150,000,000
Accounts Payable and Accrued Liabilities, Current [Abstract]
Affiliated accounts payable	80,445,000	70,299,000
Other accounts payable	176,142,000	210,191,000
Customer deposits	14,980,000	14,379,000
Accrued taxes --
Accrued income taxes	16,732,000	5,590,000
Other accrued taxes	45,135,000	77,958,000
Accrued interest	60,386,000	47,144,000
Accrued compensation	12,958,000	9,324,000
Other regulatory liabilities, current	19,937,000	24,981,000
Over recovered regulatory clause liabilities	0	18,358,000
Other current liabilities	19,612,000	21,413,000
Total current liabilities	1,097,497,000	663,426,000
Long-term debt, affiliated	220,000,000	0
Long-term debt, non-affiliated	2,011,293,000	2,167,067,000
Long-term Debt	2,231,293,000	2,167,067,000
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	19,157,000	72,808,000
Deferred credits related to income taxes	7,553,000	9,145,000
Accumulated deferred investment tax credits	283,671,000	284,248,000
Employee benefit obligations	94,164,000	94,430,000
Asset retirement obligations	42,169,000	41,197,000
Other cost of removal obligations	160,277,000	151,340,000
Other regulatory liabilities, deferred	213,827,000	140,880,000
Other deferred credits and liabilities	12,203,000	14,337,000
Total deferred credits and other liabilities	833,021,000	808,385,000
Total Liabilities	4,161,811,000	3,638,878,000
Redeemable Preferred Stock	32,780,000	32,780,000
Common Stockholders' Equity:
Common stock	37,691,000	37,691,000
Paid-in capital	2,479,564,000	2,376,595,000
Retained earnings	(339,424,000)	(229,871,000)
Accumulated other comprehensive loss	(7,439,000)	(7,864,000)
Total common stockholders' equity	2,170,392,000	2,176,551,000
Total Liabilities and Stockholders' Equity	6,364,983,000	5,848,209,000
Southern Power [Member]
Current Assets:
Cash and cash equivalents	23,616,000	68,744,000
Receivables --
Customer accounts receivable	106,162,000	73,497,000
Other accounts and notes receivable	8,041,000	3,983,000
Affiliated companies	36,257,000	38,391,000
Fossil fuel stock, at average cost	20,414,000	19,178,000
Materials and supplies, at average cost	57,906,000	54,780,000
Prepaid service agreements - current	29,676,000	81,206,000
Prepaid income taxes	77,488,000	54,732,000
Prepaid expenses	5,769,000	7,915,000
Assets from risk management activities	289,000	182,000
Total current assets	365,618,000	402,608,000
Property, Plant, and Equipment:
In service	4,942,635,000	4,696,134,000
Less accumulated provision for depreciation	922,461,000	871,963,000
Plant in service, net of depreciation	4,020,174,000	3,824,171,000
Construction work in progress	10,237,000	9,843,000
Total property, plant, and equipment	4,030,411,000	3,834,014,000
Other Property and Investments:
Goodwill	1,839,000	1,839,000
Other intangible assets, net of amortization of $6,232 and $5,614 at March 31, 2014 and December 31, 2013, respectively	42,269,000	43,505,000
Total other property and investments	44,108,000	45,344,000
Deferred Charges and Other Assets:
Prepaid long-term service agreements	69,326,000	73,676,000
Other deferred charges and assets -- affiliated	7,767,000	4,605,000
Other deferred charges and assets	87,814,000	68,853,000
Total deferred charges and other assets	164,907,000	147,134,000
Total Assets	4,605,044,000	4,429,100,000
Current Liabilities:
Securities due within one year	2,082,000	599,000
Notes payable	73,482,000	0
Accounts Payable and Accrued Liabilities, Current [Abstract]
Affiliated accounts payable	80,052,000	56,661,000
Other accounts payable	18,031,000	20,747,000
Accrued taxes --
Accrued income taxes	1,585,000	161,000
Other accrued taxes	10,052,000	2,662,000
Accrued interest	28,446,000	28,352,000
Other current liabilities	22,786,000	18,492,000
Total current liabilities	236,516,000	127,674,000
Long-term Debt	1,626,908,000	1,619,241,000
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	727,923,000	724,390,000
Deferred convertible investment tax credits	398,397,000	340,269,000
Deferred capacity revenues -- affiliated	6,629,000	15,279,000
Other deferred credits and liabilities — affiliated	1,113,000	1,621,000
Other deferred credits and liabilities	10,261,000	7,896,000
Total deferred credits and other liabilities	1,144,323,000	1,089,455,000
Total Liabilities	3,007,747,000	2,836,370,000
Redeemable Noncontrolling Interest	37,841,000	28,778,000
Common Stockholders' Equity:
Common stock	0	0
Paid-in capital	1,025,618,000	1,029,035,000
Retained earnings	530,722,000	531,998,000
Accumulated other comprehensive loss	3,116,000	2,919,000
Total common stockholders' equity	1,559,456,000	1,563,952,000
Total Liabilities and Stockholders' Equity	$ 4,605,044,000	$ 4,429,100,000

XML

Condensed Consolidated Statements of Comprehensive Income (Unaudited) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Pension and other post retirement benefit plans:
Total other comprehensive income (loss)			$ 4,000,000	$ 9,000,000
Southern Company [Member]
Net Income	628,000,000	313,000,000	996,000,000	410,000,000
Qualifying hedges:
Reclassification adjustment for amounts included in net income, net of tax	1,000,000	3,000,000	2,000,000	6,000,000
Pension and other post retirement benefit plans:
Reclassification adjustment for amounts included in net income, net of tax	1,000,000	2,000,000	2,000,000	3,000,000
Total other comprehensive income (loss)	2,000,000	5,000,000	4,000,000	9,000,000
Less: Comprehensive income attributable to noncontrolling interest	(17,000,000)	(16,000,000)	(34,000,000)	(32,000,000)
Comprehensive Income	613,000,000	302,000,000	966,000,000	387,000,000
Alabama Power [Member]
Net Income	183,000,000	183,000,000	380,000,000	334,000,000
Qualifying hedges:
Reclassification adjustment for amounts included in net income, net of tax	0	1,000,000	1,000,000	1,000,000
Pension and other post retirement benefit plans:
Total other comprehensive income (loss)	0	1,000,000	1,000,000	1,000,000
Comprehensive Income	183,000,000	184,000,000	381,000,000	335,000,000
Georgia Power [Member]
Net Income	316,000,000	287,000,000	586,000,000	488,000,000
Qualifying hedges:
Reclassification adjustment for amounts included in net income, net of tax	1,000,000	0	1,000,000	1,000,000
Pension and other post retirement benefit plans:
Total other comprehensive income (loss)	1,000,000	0	1,000,000	1,000,000
Comprehensive Income	317,000,000	287,000,000	587,000,000	489,000,000
Gulf Power [Member]
Net Income	36,347,000	34,233,000	75,341,000	57,576,000
Qualifying hedges:
Reclassification adjustment for amounts included in net income, net of tax	93,000	143,000	186,000	286,000
Pension and other post retirement benefit plans:
Total other comprehensive income (loss)	93,000	143,000	186,000	286,000
Comprehensive Income	36,440,000	34,376,000	75,527,000	57,862,000
Mississippi Power [Member]
Net Income	62,928,000	(218,677,000)	(108,687,000)	(464,565,000)
Qualifying hedges:
Changes in fair value, net of tax	1,000	0	0	0
Reclassification adjustment for amounts included in net income, net of tax	212,000	213,000	425,000	425,000
Pension and other post retirement benefit plans:
Total other comprehensive income (loss)	213,000	213,000	425,000	425,000
Comprehensive Income	63,141,000	(218,464,000)	(108,262,000)	(464,140,000)
Southern Power [Member]
Net Income	32,044,000	27,922,000	66,330,000	57,114,000
Qualifying hedges:
Changes in fair value, net of tax	2,000	0	0	0
Reclassification adjustment for amounts included in net income, net of tax	108,000	1,647,000	197,000	3,281,000
Pension and other post retirement benefit plans:
Total other comprehensive income (loss)	110,000	1,647,000	197,000	3,281,000
Less: Comprehensive income attributable to noncontrolling interest	(1,232,000)	0	(2,047,000)	0
Comprehensive Income	$ 30,922,000	$ 29,569,000	$ 64,480,000	$ 60,395,000

XML

Acquisitions

6 Months Ended

Jun. 30, 2014

Business Combinations [Abstract]

ACQUISITIONS

ACQUISITIONS

Adobe Solar, LLC

See Note 2 to the financial statements of Southern Power under "Adobe Solar, LLC" in Item 8 of the Form 10-K for additional information.

On April 17, 2014, Southern Power and TRE, through Southern Turner Renewable Energy, LLC (STR), a jointly-owned subsidiary owned 90% by Southern Power, acquired all of the outstanding membership interests of Adobe Solar, LLC (Adobe) from Sun Edison, LLC, the original developer of the project. Adobe constructed and owns an approximately 20-MW solar photovoltaic facility in Kern County, California. The solar facility began commercial operation on May 21, 2014 and has the entire output of the plant contracted under a 20-year PPA with Southern California Edison Company. The acquisition is in accordance with Southern Power's overall growth strategy.

Southern Power's acquisition of Adobe included cash consideration of approximately $90.5 million. The outstanding balance of $4.7 million remains to be paid upon completion of certain milestones. As of June 30, 2014, the purchase price was recorded primarily as property, plant, and equipment with $13.4 million recorded in receivables reflecting reimbursable transmission costs; however, the allocation of the purchase price to individual assets has not been finalized. The acquisition did not include any contingent consideration. Acquisition-related costs were expensed as incurred and were not material.

Macho Springs Solar, LLC

On May 22, 2014, Southern Power and TRE, through STR, acquired all of the outstanding membership interests ofMacho Springs Solar, LLC (Macho Springs) from First Solar Development, LLC, the original developer of the project. Macho Springs constructed and owns an approximately50-MW solar photovoltaic facility in Luna County, New Mexico. The solar facility began commercial operation on May 23,2014and has the entire output of the plant contracted under a20-year PPA withEl Paso Electric Company. The acquisition is in accordance with Southern Power's overall growth strategy.

Southern Power's acquisition of Macho Springs included cash consideration of approximately $130.0 million. As of June 30, 2014, the purchase price was recorded primarily as property, plant, and equipment; however, the allocation of the purchase price to individual assets has not been finalized. The acquisition did not include any contingent consideration. Acquisition-related costs were expensed as incurred and were not material.

XML

Document and Entity Information	6 Months Ended
	Jun. 30, 2014
Entity Information [Line Items]
Entity Registrant Name	SOUTHERN CO
Entity Central Index Key	0000092122
Document Type	10-Q
Document Period End Date	Jun. 30, 2014
Amendment Flag	false
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	Q2
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding	895,696,608
Alabama Power [Member]
Entity 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]
Entity 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]
Entity 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	5,442,717
Mississippi Power [Member]
Entity 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]
Entity 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

6 Months Ended

Jun. 30, 2014

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 $68 million and $140 million for the three and six months ended June 30, 2014, respectively, and $89 million and $167 million for the three and six months ended June 30, 2013, 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 and six months ended June 30, 2014 and 2013 was as follows:

	Electric Utilities
	Traditional Operating Companies		Southern Power		Eliminations			Total		All Other			Eliminations			Consolidated
	(in millions)
Three Months Ended June 30, 2014:
Operating revenues	$	4,209	$	329	$	(84	)	$	4,454	$	39		$	(26	)	$	4,467
Segment net income (loss)(a)	580		31		—			611		2			(2		)	611
Six Months Ended June 30, 2014:
Operating revenues	$	8,587	$	680	$	(186	)	$	9,081	$	80		$	(50	)	$	9,111
Segment net income (loss)(a)(c)	899		64		—			963		2			(3		)	962
Total assets at June 30, 2014	$	61,210	$	4,605	$	(132	)	$	65,683	$	1,356		$	(639	)	$	66,400
Three Months Ended June 30, 2013:
Operating revenues	$	4,018	$	307	$	(95	)	$	4,230	$	38		$	(22	)	$	4,246
Segment net income (loss)(a)(b)	268		28		—			296		4			(3		)	297
Six Months Ended June 30, 2013:
Operating revenues	$	7,687	$	610	$	(181	)	$	8,116	$	73		$	(46	)	$	8,143
Segment net income (loss)(a)(c)	334		57		—			391		(12		)	(1		)	378
Total assets at December 31, 2013	$	59,447	$	4,429	$	(101	)	$	63,775	$	1,077		$	(306	)	$	64,546

(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 June 30, 2013 includes a $450.0 million pre-tax charge ($277.9 million after tax) for an estimated probable loss on the Kemper IGCC. See Note (B) under "Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" herein for additional information.

(c) Segment net income (loss) for the traditional operating companies for the six months ended June 30, 2014 and June 30, 2013 includes $380.0 million in pre-tax charges ($234.7 million after tax) and $990.0 million in pre-tax charges ($611.3 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 June 30, 2014	$	3,770	$	515	$	169	$	4,454
Three Months Ended June 30, 2013	3,620		454		156		4,230
Six Months Ended June 30, 2014	$	7,628	$	1,119	$	334	$	9,081
Six Months Ended June 30, 2013	6,918		886		312		8,116

XML

Condensed Consolidated Statements of Comprehensive Income (Unaudited) (Parenthetical) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Southern Company [Member]
Reclassification adjustment for amounts of qualifying hedges included in net income, tax	$ 0	$ 2,000,000	$ 2,000,000	$ 4,000,000
Reclassification adjustment for amounts of pension and other post retirement benefit plans included in net income, tax	1,000,000	1,000,000	1,000,000	2,000,000
Alabama Power [Member]
Reclassification adjustment for amounts of qualifying hedges included in net income, tax	0	0	0	0
Georgia Power [Member]
Reclassification adjustment for amounts of qualifying hedges included in net income, tax	0	1,000,000	0	1,000,000
Gulf Power [Member]
Reclassification adjustment for amounts of qualifying hedges included in net income, tax	59,000	90,000	117,000	180,000
Mississippi Power [Member]
Changes in fair value, tax	1,000	0	0	0
Reclassification adjustment for amounts of qualifying hedges included in net income, tax	132,000	132,000	263,000	263,000
Southern Power [Member]
Changes in fair value, tax	1,000	0	0	0
Reclassification adjustment for amounts of qualifying hedges included in net income, tax	$ 24,000	$ 1,052,000	$ 63,000	$ 2,097,000

XML

Stockholders' Equity

6 Months Ended

Jun. 30, 2014

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 effects of both stock options and performance share award units were determined using the treasury stock method. Shares used to compute diluted earnings per share were as follows:

	Three Months Ended June 30, 2014	Three Months Ended June 30, 2013	Six Months Ended June 30, 2014	Six Months Ended June 30, 2013
	(in millions)
As reported shares	895	874	892	872
Effect of options and performance share award units	4	5	4	5
Diluted shares	899	879	896	877

Stock options and performance share award units that were not included in the diluted earnings per share calculation because they were anti-dilutive were 8 million and 17 million for the three and six months ended June 30, 2014, respectively, and were immaterial for the three and six months ended June 30, 2013.

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
	(in thousands)						(in millions)
Balance at December 31, 2013	892,733	(5,647	)	$	19,008		$	756	$	19,764
Net income after dividends on preferred and preference stock	—	—		962			—		962
Other comprehensive income (loss)	—	—		4			—		4
Treasury stock re-issued	—	4,739		216			—		216
Stock issued	3,898	—		161			—		161
Stock repurchased, at cost	—	—		(5		)	—		(5		)
Cash dividends on common stock	—	—		(920		)	—		(920		)
Other	—	(27	)	—			—		—
Balance at June 30, 2014	896,631	(935	)	$	19,426		$	756	$	20,182
Balance at December 31, 2012	877,803	(10,035	)	$	18,297		$	707	$	19,004
Net income after dividends on preferred and preference stock	—	—		378			—		378
Other comprehensive income (loss)	—	—		9			—		9
Stock issued	6,144	—		244			49		293
Stock repurchased, at cost	—	—		(18		)	—		(18		)
Cash dividends on common stock	—	—		(870		)	—		(870		)
Other	—	(9	)	—			—		—
Balance at June 30, 2013	883,947	(10,044	)	$	18,040		$	756	$	18,796

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Fair Value Measurements

6 Months Ended

Jun. 30, 2014

Fair Value Disclosures [Abstract]

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS

As of June 30, 2014, 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 June 30, 2014:	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	$	—	$	40	$	—	$	40
Nuclear decommissioning trusts(a)	651		877		2		1,530
Cash equivalents	321		—		—		321
Other investments	9		—		4		13
Total	$	981	$	917	$	6	$	1,904
Liabilities:
Energy-related derivatives	$	—	$	36	$	—	$	36
Alabama Power
Assets:
Energy-related derivatives	$	—	$	14	$	—	$	14
Nuclear decommissioning trusts(b)
Domestic equity	408		81		—		489
Foreign equity	36		68		—		104
U.S. Treasury and government agency securities	—		33		—		33
Corporate bonds	—		95		—		95
Mortgage and asset backed securities	—		20		—		20
Other	—		5		2		7
Total	$	444	$	316	$	2	$	762
Liabilities:
Energy-related derivatives	$	—	$	5	$	—	$	5

	Fair Value Measurements Using
As of June 30, 2014:	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	$	—	$	7	$	—	$	7
Nuclear decommissioning trusts(b) (c)
Domestic equity	194		1		—		195
Foreign equity	—		138		—		138
U.S. Treasury and government agency securities	—		132		—		132
Municipal bonds	—		34		—		34
Corporate bonds	—		157		—		157
Mortgage and asset backed securities	—		108		—		108
Other	13		5		—		18
Total	$	207	$	582	$	—	$	789
Liabilities:
Energy-related derivatives	$	—	$	15	$	—	$	15
Gulf Power
Assets:
Energy-related derivatives	$	—	$	12	$	—	$	12
Cash equivalents	18		—		—		18
Total	$	18	$	12	$	—	$	30
Liabilities:
Energy-related derivatives	$	—	$	11	$	—	$	11
Mississippi Power
Assets:
Energy-related derivatives	$	—	$	7	$	—	$	7
Cash equivalents	205		—		—		205
Total	$	205	$	7	$	—	$	212
Liabilities:
Energy-related derivatives	$	—	$	5	$	—	$	5
Southern Power
Assets:
Cash equivalents	$	17	$	—	$	—	$	17
Total	$	17	$	—	$	—	$	17

(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, and payables related to pending investment purchases.

(c) Includes the investment securities pledged to creditors and cash collateral received and excludes payables related to the securities lending program. As of June 30, 2014, approximately $49 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 and foreign currency 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. Inputs for foreign currency derivatives are from observable market sources. See Note (H) herein for additional information on how these derivatives are used.

For fair value measurements of investments within the nuclear decommissioning trusts, specifically the fixed income assets using significant other observable inputs and unobservable inputs, the primary valuation technique used is the market approach. External pricing vendors are designated for each of the asset classes in the nuclear decommissioning trusts with each security discriminately assigned a primary pricing source, based on similar characteristics. 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, 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 the 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 in funds that are valued using the market approach and income approach. Securities that are traded in the open market are valued at the closing price on their principal exchange as of the measurement date. Discounts are applied in accordance with GAAP when certain trading restrictions exist. For investments that are not traded in the open market, the price paid will have been determined based on market factors including comparable multiples and the expectations regarding cash flows and business plan execution. As the investments mature or if market conditions change materially, further analysis of the fair market value of the investment is performed. This analysis is typically based on a metric, such as multiple of earnings, revenues, earnings before interest and income taxes, or earnings adjusted for certain cash changes. These multiples are based on comparable multiples for publicly traded companies or other relevant prior transactions.

As of June 30, 2014, 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 June 30, 2014:	Fair Value		Unfunded Commitments	Redemption Frequency	Redemption Notice Period
	(in millions)
Southern Company
Nuclear decommissioning trusts:
Foreign equity funds	$	138	None	Monthly	5 days
Equity - commingled funds	68		None	Daily/Monthly	Daily/7 days
Other - commingled funds	5		None	Daily	Not applicable
Other - money market funds	13		None	Daily	Not applicable
Trust-owned life insurance	114		None	Daily	15 days
Cash equivalents:
Money market funds	321		None	Daily	Not applicable
Alabama Power
Nuclear decommissioning trusts:
Equity - commingled funds	$	68	None	Daily/Monthly	Daily/7 days
Trust-owned life insurance	114		None	Daily	15 days
Georgia Power
Nuclear decommissioning trusts:
Foreign equity funds	$	138	None	Monthly	5 days
Other - commingled funds	5		None	Daily	Not applicable
Other - money market funds	13		None	Daily	Not applicable
Gulf Power
Cash equivalents:
Money market funds	$	18	None	Daily	Not applicable
Mississippi Power
Cash equivalents:
Money market funds	$	205	None	Daily	Not applicable
Southern Power
Cash equivalents:
Money market funds	$	17	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 commingled funds in Georgia Power's nuclear decommissioning trusts are invested primarily in a diversified portfolio, including, but not limited to, commercial paper, notes, repurchase agreements, and other evidences of indebtedness with a maturity not exceeding 13 months from the date of purchase. The commingled funds will, however, generally maintain a dollar-weighted average portfolio maturity of 90 days or less. The assets may be longer term investment grade fixed income obligations with maturity shortening provisions. The primary objective for the commingled funds is a high level of current income consistent with stability of principal and liquidity. Included in commingled funds as of June 30, 2014 is $5 million representing the investment of cash collateral received under the Funds' managers' securities lending program that can only be sold upon the return of the loaned securities. The money market fund within Georgia Power's nuclear decommissioning trusts represents the short-term investment of the trusts' excess cash with the goal of providing the highest possible level of income while preserving capital and maintaining liquidity. The fund's positions are in high-quality, short-term, liquid money market instruments including, but not limited to, commercial paper, floating and variable rate demand notes, debt securities issued or guaranteed by the U.S. government and its agencies, time deposits, repurchase agreements, municipal obligations, and other high-quality, short-term debt securities. The fund maintains a dollar-weighted average maturity of 60 days or less and is regulated by, and subject to, the money market regulatory requirements set by the SEC. 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 trust includes investments in Trust-Owned Life Insurance (TOLI). The taxable nuclear decommissioning trust invests in the TOLI in order to minimize the impact of taxes on the portfolio 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 trust does 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. The commingled funds 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, to some degree, 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 and six months ended June 30, 2014, the change in fair value of the funds, including reinvested interest and dividends reduced by the funds' expenses, increased by $56 million and $83 million, respectively, at Southern Company. Alabama Power recorded an increase in fair value of $31 million and $47 million, respectively, as an increase in regulatory liabilities. Georgia Power recorded an increase in fair value of $25 million and $36 million, respectively, as a reduction of its regulatory asset related to its asset retirement obligations.

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 June 30, 2014, 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	$	22,542	$	23,883
Alabama Power	$	6,229	$	6,800
Georgia Power	$	9,557	$	10,112
Gulf Power	$	1,246	$	1,306
Mississippi Power	$	2,577	$	2,571
Southern Power	$	1,629	$	1,752

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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Financing (Tables)

6 Months Ended

Jun. 30, 2014

Debt Disclosure [Abstract]

Credit arrangements by company

The following table outlines the committed credit arrangements by company as of June 30, 2014:

	Expires														Executable Term Loans				Due Within One Year
Company	2014		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	163		110		—		—		1,030		1,303		1,303		53		—		53		185
Georgia Power	—		—		150		—		1,600		1,750		1,736		—		—		—		—
Gulf Power	20		60		165		30		—		275		275		50		—		50		30
Mississippi Power	40		95		165		—		—		300		300		25		40		65		70
Southern Power	—		—		—		—		500		500		499		—		—		—		—
Other	—		70		—		—		—		70		70		20		—		20		25
Total	$	223	$	335	$	480	$	30	$	4,130	$	5,198	$	5,183	$	148	$	40	$	188	$	310

Schedule of Long-term Debt Financing Activities

The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first six months of 2014:

Company(a)	Senior Note Maturities		Revenue Bond Issuances and Remarketings of Purchased Bonds(b)		Revenue Bond Redemptions		Other Long-Term Debt Issuances			Other Long-Term Debt Redemptions(c)
	(in millions)
Southern Company	$	350	$	—	$	—	$	—		$	—
Georgia Power	—		—		37		1,000			3
Gulf Power	—		42		29		—			—
Mississippi Power	—		—		—		482			1
Southern Power	—		—		—		10			1
Other	—		—		—		—			10
Elimination(d)	—		—		—		(220		)	—
Total	$	350	$	42	$	66	$	1,272		$	15

(a) Alabama Power did not issue or redeem any long-term debt during the first six months of 2014.

(b) Includes remarketing by Gulf Power of $13 million aggregate principal amount of revenue bonds previously purchased and held by Gulf Power since December 2013.

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

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

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Introduction (Policies)

6 Months Ended

Jun. 30, 2014

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Depreciation

Depreciation

Beginning in 2014, Southern Power changed the method of depreciation for its property, plant, and equipment from composite depreciation to component depreciation. As a result, certain generation assets are depreciated on a units-of-production basis to better match outage and maintenance costs to the usage of, and revenues from, these assets. The difference in depreciation expense under this method was not material in the first and second quarters 2014 and is not expected to have a material impact on the financial statements of Southern Company or Southern Power in future periods.

Recently Issued Accounting Standards

Recently Issued Accounting Standards

On May 28, 2014, the Financial Accounting Standards Board issued ASC 606, Revenue from Contracts with Customers. ASC 606 revises the accounting for revenue recognition and is effective for fiscal years beginning after December 15, 2016. The registrants are currently evaluating the requirements of ASC 606. The ultimate impact of the new standard has not yet been determined.

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 and foreign currency 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. Inputs for foreign currency derivatives are from observable market sources. See Note (H) herein for additional information on how these derivatives are used.

For fair value measurements of investments within the nuclear decommissioning trusts, specifically the fixed income assets using significant other observable inputs and unobservable inputs, the primary valuation technique used is the market approach. External pricing vendors are designated for each of the asset classes in the nuclear decommissioning trusts with each security discriminately assigned a primary pricing source, based on similar characteristics. 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, 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 the 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 in funds that are valued using the market approach and income approach. Securities that are traded in the open market are valued at the closing price on their principal exchange as of the measurement date. Discounts are applied in accordance with GAAP when certain trading restrictions exist. For investments that are not traded in the open market, the price paid will have been determined based on market factors including comparable multiples and the expectations regarding cash flows and business plan execution. As the investments mature or if market conditions change materially, further analysis of the fair market value of the investment is performed. This analysis is typically based on a metric, such as multiple of earnings, revenues, earnings before interest and income taxes, or earnings adjusted for certain cash changes. These multiples are based on comparable multiples for publicly traded companies or other relevant prior transactions.

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 effects of both stock options and performance share award units were determined using the treasury stock method.

Energy-Related Derivatives and Interest Rate Derivatives

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, Southern Power has been and may continue to be exposed to market volatility in energy-related commodity prices as a result of sales from its uncontracted generating capacity. Further, the traditional operating companies may be exposed to market volatility in energy-related commodity prices to the extent any uncontracted wholesale generating capacity is used to sell electricity. Gulf Power currently has long-term sales agreements for 100% of its wholesale capacity through 2015 and 57% through 2018.

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.

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.

Foreign Currency Derivatives

Foreign Currency Derivatives

Southern Company and certain subsidiaries may enter into foreign currency derivatives to hedge exposure to changes in foreign currency exchange rates arising from purchases of equipment denominated in a currency other than U.S. dollars. Derivatives related to a firm commitment in a foreign currency transaction are accounted for as fair value hedges where the derivatives' fair value gains or losses and the hedged items' fair value gains or losses are both recorded directly to earnings. Derivatives related to a forecasted transaction 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. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. Any ineffectiveness is recorded directly to earnings; however, Mississippi Power has regulatory approval allowing it to defer any ineffectiveness associated with firm commitments related to the Kemper IGCC to a regulatory asset.

At June 30, 2014, there were no foreign currency derivatives outstanding.

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Effective Tax Rate

6 Months Ended

Jun. 30, 2014

Income Tax Disclosure [Abstract]

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 33.3% for the six months ended June 30, 2014 compared to 31.4% for the corresponding period in 2013. The increase was primarily due to higher net income, which was partially offset by an increase in non-taxable AFUDC equity, changes in state apportionment, and beneficial changes in certain state income tax laws.

Alabama Power

Alabama Power's effective tax rate was 39.3% for the six months ended June 30, 2014 compared to 39.2% for the corresponding period in 2013.

Georgia Power

Georgia Power's effective tax rate was 37.0% for the six months ended June 30, 2014 compared to 38.2% for the corresponding period in 2013. The decrease was primarily due to recognition in the second quarter 2014 of tax benefits related to emission allowances and state apportionment.

Gulf Power

Gulf Power's effective tax rate was 37.3% for the six months ended June 30, 2014 compared to 37.7% for the corresponding period in 2013.

Mississippi Power

Mississippi Power's effective tax rate was (51.1)% for the six months ended June 30, 2014 compared to (41.0)% for the corresponding period in 2013. The change in the tax benefit was primarily due to a reduced net loss for the current period compared to the corresponding period in 2013 and an increase in non-taxable AFUDC equity related to the construction of the Kemper IGCC.

Southern Power

Southern Power's effective tax rate was 0.3% for the six months ended June 30, 2014 compared to 25.1% for the corresponding period in 2013. The decrease was primarily due to the impact of state apportionment changes which reduced Southern Power's deferred tax liabilities, a change in filing method for North Carolina income tax, an increase in state income tax credits, and beneficial changes in certain state income tax laws.

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Financing

6 Months Ended

Jun. 30, 2014

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 requiring liquidity support as of June 30, 2014 was approximately $1.7 billion. In addition, at June 30, 2014, the traditional operating companies had $495 million of fixed rate pollution control revenue bonds that will be 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.

The following table outlines the committed credit arrangements by company as of June 30, 2014:

	Expires														Executable Term Loans				Due Within One Year
Company	2014		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	163		110		—		—		1,030		1,303		1,303		53		—		53		185
Georgia Power	—		—		150		—		1,600		1,750		1,736		—		—		—		—
Gulf Power	20		60		165		30		—		275		275		50		—		50		30
Mississippi Power	40		95		165		—		—		300		300		25		40		65		70
Southern Power	—		—		—		—		500		500		499		—		—		—		—
Other	—		70		—		—		—		70		70		20		—		20		25
Total	$	223	$	335	$	480	$	30	$	4,130	$	5,198	$	5,183	$	148	$	40	$	188	$	310

Southern Company and its subsidiaries expect to renew their 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 six months of 2014:

Company(a)	Senior Note Maturities		Revenue Bond Issuances and Remarketings of Purchased Bonds(b)		Revenue Bond Redemptions		Other Long-Term Debt Issuances			Other Long-Term Debt Redemptions(c)
	(in millions)
Southern Company	$	350	$	—	$	—	$	—		$	—
Georgia Power	—		—		37		1,000			3
Gulf Power	—		42		29		—			—
Mississippi Power	—		—		—		482			1
Southern Power	—		—		—		10			1
Other	—		—		—		—			10
Elimination(d)	—		—		—		(220		)	—
Total	$	350	$	42	$	66	$	1,272		$	15

(a) Alabama Power did not issue or redeem any long-term debt during the first six months of 2014.

(b) Includes remarketing by Gulf Power of $13 million aggregate principal amount of revenue bonds previously purchased and held by Gulf Power since December 2013.

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

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

Georgia Power

Pursuant to the loan guarantee program established under Title XVII of the Energy Policy Act of 2005, Georgia Power and the DOE entered into a loan guarantee agreement (Loan Guarantee Agreement) on February 20, 2014, under which the DOE agreed to guarantee the obligations of Georgia Power under a note purchase agreement (FFB Note Purchase Agreement) among the DOE, Georgia Power, and the FFB and a related promissory note (FFB Promissory Note). Georgia Power is obligated to reimburse the DOE for any payments the DOE is required to make to the FFB under the guarantee.

The FFB Note Purchase Agreement and the FFB Promissory Note provide for a multi-advance term loan facility (FFB Credit Facility), under which Georgia Power may make term loan borrowings through the FFB. On February 20, 2014, Georgia Power made initial borrowings under the FFB Credit Facility in an aggregate principal amount of $1.0 billion. Georgia Power's reimbursement obligations to the DOE are secured by a first priority lien on (i) Georgia Power's 45.7% undivided ownership interest in Plant Vogtle Units 3 and 4 (primarily the units under construction, the related real property, and any nuclear fuel loaded in the reactor core) and (ii) Georgia Power's rights and obligations under the principal contracts relating to Plant Vogtle Units 3 and 4. The interest rate applicable to $500 million of the initial advance under the FFB Credit Facility is 3.860% for an interest period that extends to February 20, 2044 (the final maturity date) and the interest rate applicable to the remaining $500 million is 3.488% for an interest period that extends to February 20, 2029, and is expected to be reset from time to time thereafter through the final maturity date. In connection with its entry into the Loan Guarantee Agreement, the FFB Note Purchase Agreement, and the FFB Promissory Note, Georgia Power incurred issuance costs of approximately $66 million, which will be amortized over the life of the borrowings under the FFB Credit Facility.

See Note 6 to the financial statements of Southern Company and Georgia Power in Item 8 of the Form 10-K under "DOE Loan Guarantee Borrowings" for additional information.

Gulf Power

In April 2014, Gulf Power executed a loan agreement with Mississippi Business Finance Corporation (MBFC) related to MBFC's issuance of $29.075 million aggregate principal amount of Pollution Control Revenue Refunding Bonds, First Series 2014 (Gulf Power Company Project) due April 1, 2044 for the benefit of Gulf Power. The proceeds were used to redeem $29.075 million aggregate principal amount of MBFC Pollution Control Revenue Refunding Bonds, Series 2003 (Gulf Power Company Project).

In June 2014, Gulf Power reoffered to the public $13 million aggregate principal amount of MBFC Solid Waste Disposal Facilities Revenue Refunding Bonds, Series 2012 (Gulf Power Company Project), which had been previously purchased and held by Gulf Power since December 2013.

Mississippi Power

In January 2014, Mississippi Power entered into an 18-month floating rate bank loan bearing interest based on one-month LIBOR. This term loan was for $250 million aggregate principal amount, and proceeds were used for working capital and other general corporate purposes, including Mississippi Power's continuous construction program.

In January 2014, Mississippi Power received an additional $75 million interest-bearing refundable deposit from SMEPA to be applied to the sale price for the pending sale of an undivided interest in the Kemper IGCC. See Note 3 to the financial statements of Southern Company and Mississippi Power in Item 8 of the Form 10-K under "Integrated Coal Gasification Combined Cycle – Proposed Sale of Undivided Interest to SMEPA" for additional information.

As reflected in the table above in "Other Long-Term Debt Issuances," in May 2014, Mississippi Power issued a 19-month floating rate promissory note to Southern Company for a loan bearing interest based on one-month LIBOR. This loan was for $220 million aggregate principal amount and the proceeds were used for working capital and other general corporate purposes, including Mississippi Power's construction program.

Also in May 2014, the MBFC issued $12.3 million aggregate principal amount of MBFC Taxable Revenue Bonds (Mississippi Power Company Project), Series 2013A for the benefit of Mississippi Power and proceeds were used to reimburse Mississippi Power for the cost of the acquisition, construction, equipping, installation, and improvement of certain equipment and facilities for the lignite mining facility related to the Kemper IGCC. Any future issuances of the Series 2013A bonds will be used for this same purpose.

Southern Power

During the six months ended June 30, 2014, Southern Power prepaid $0.8 million of long-term debt to TRE and issued $3.8 million due April 30, 2034, $5.3 million due May 31, 2034, and an additional $0.8 million due April 30, 2033 under promissory notes payable to TRE related to the financing of Adobe, Macho Springs, and Campo Verde Solar, LLC, respectively.

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Retirement Benefits

6 Months Ended

Jun. 30, 2014

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, 2014. 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 and six months ended June 30, 2014 and 2013 were as follows:

Pension Plans	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power
	(in millions)
Three Months Ended June 30, 2014
Service cost	$	54		$	12		$	15		$	1		$	2
Interest cost	108			26			38			5			5
Expected return on plan assets	(162		)	(42		)	(56		)	(7		)	(7		)
Amortization:
Prior service costs	7			2			2			1			1
Net (gain)/loss	27			8			10			1			1
Net cost	$	34		$	6		$	9		$	1		$	2
Six Months Ended June 30, 2014
Service cost	$	107		$	24		$	31		$	4		$	5
Interest cost	217			52			76			10			10
Expected return on plan assets	(323		)	(84		)	(113		)	(14		)	(14		)
Amortization:
Prior service costs	13			3			5			1			1
Net (gain)/loss	55			16			20			2			2
Net cost	$	69		$	11		$	19		$	3		$	4
Three Months Ended June 30, 2013
Service cost	$	58		$	14		$	18		$	2		$	2
Interest cost	97			23			35			5			4
Expected return on plan assets	(150		)	(39		)	(53		)	(7		)	(6		)
Amortization:
Prior service costs	6			1			2			1			—
Net (gain)/loss	50			13			18			2			3
Net cost	$	61		$	12		$	20		$	3		$	3
Six Months Ended June 30, 2013
Service cost	$	116		$	27		$	35		$	5		$	5
Interest cost	194			46			69			9			9
Expected return on plan assets	(301		)	(78		)	(106		)	(13		)	(13		)
Amortization:
Prior service costs	13			3			5			1			—
Net (gain)/loss	100			26			37			4			5
Net cost	$	122		$	24		$	40		$	6		$	6

Postretirement Benefits	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power
	(in millions)
Three Months Ended June 30, 2014
Service cost	$	6		$	2		$	1		$	1		$	1
Interest cost	20			5			9			1			1
Expected return on plan assets	(15		)	(7		)	(7		)	(1		)	(1		)
Amortization:
Prior service costs	1			1			—			—			—
Net (gain)/loss	—			—			1			—			—
Net cost	$	12		$	1		$	4		$	1		$	1
Six Months Ended June 30, 2014
Service cost	$	11		$	3		$	3		$	1		$	1
Interest cost	40			10			17			2			2
Expected return on plan assets	(30		)	(13		)	(13		)	(1		)	(1		)
Amortization:
Prior service costs	2			2			—			—			—
Net (gain)/loss	1			—			1			—			—
Net cost	$	24		$	2		$	8		$	2		$	2
Three Months Ended June 30, 2013
Service cost	$	6		$	1		$	1		$	1		$	1
Interest cost	18			4			8			—			1
Expected return on plan assets	(14		)	(6		)	(6		)	—			(1		)
Amortization:
Transition obligation	1			—			1			—			—
Prior service costs	1			1			—			—			—
Net (gain)/loss	3			1			2			—			—
Net cost	$	15		$	1		$	6		$	1		$	1
Six Months Ended June 30, 2013
Service cost	$	12		$	3		$	3		$	1		$	1
Interest cost	37			9			16			1			2
Expected return on plan assets	(28		)	(12		)	(12		)	—			(1		)
Amortization:
Transition obligation	2			—			2			—			—
Prior service costs	2			2			—			—			—
Net (gain)/loss	6			1			4			—			—
Net cost	$	31		$	3		$	13		$	2		$	2

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Derivatives

6 Months Ended

Jun. 30, 2014

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, interest rate risk, and occasionally foreign currency risk. To manage the volatility attributable to these exposures, each company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to each company's policies in areas such as counterparty exposure and risk management practices. Each company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a gross basis. In the statements of cash flows, the cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities and the cash impacts of settled foreign currency derivatives are recorded as investing 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, Southern Power has been and may continue to be exposed to market volatility in energy-related commodity prices as a result of sales from its uncontracted generating capacity. Further, the traditional operating companies may be exposed to market volatility in energy-related commodity prices to the extent any uncontracted wholesale generating capacity is used to sell electricity. Gulf Power currently has long-term sales agreements for 100% of its wholesale capacity through 2015 and 57% through 2018.

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 June 30, 2014, the net volume of energy-related derivative contracts for natural gas positions for the Southern Company system, together with the longest hedge date over which the respective entity is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest non-hedge date for derivatives not designated as hedges, were as follows:

	Net Purchased mmBtu	Longest Hedge Date	Longest Non-Hedge Date
	(in millions)
Southern Company	250	2018	2017
Alabama Power	63	2017	—
Georgia Power	50	2017	—
Gulf Power	85	2018	—
Mississippi Power	51	2017	—
Southern Power	1	—	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 8 million mmBtu for Southern Company, 1 million mmBtu for Alabama Power, 5 million mmBtu for Georgia Power, 1 million mmBtu for Gulf 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 June 30, 2015 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 June 30, 2014, the following interest rate derivatives were outstanding:

	Notional Amount		Interest Rate Received	Weighted Average Interest Rate Paid	Hedge Maturity Date	Fair Value Gain (Loss) June 30, 2014
	(in millions)					(in millions)
Cash flow hedges of forecasted debt
Alabama Power	$	75	3-month LIBOR	3.12%	October 2025	$	—

The estimated pre-tax gains (losses) that will be reclassified from accumulated OCI to interest expense for the next 12-month period ending June 30, 2015 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.

Foreign Currency Derivatives

Southern Company and certain subsidiaries may enter into foreign currency derivatives to hedge exposure to changes in foreign currency exchange rates arising from purchases of equipment denominated in a currency other than U.S. dollars. Derivatives related to a firm commitment in a foreign currency transaction are accounted for as fair value hedges where the derivatives' fair value gains or losses and the hedged items' fair value gains or losses are both recorded directly to earnings. Derivatives related to a forecasted transaction 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. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. Any ineffectiveness is recorded directly to earnings; however, Mississippi Power has regulatory approval allowing it to defer any ineffectiveness associated with firm commitments related to the Kemper IGCC to a regulatory asset.

At June 30, 2014, there were no foreign currency derivatives outstanding.

Derivative Financial Statement Presentation and Amounts

At June 30, 2014, the fair value of energy-related derivatives was reflected in the balance sheets as follows:

Asset Derivatives at June 30, 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	$	31	$	12	$	6	$	8	$	5
Other deferred charges and assets	9		2		1		4		2
Total asset derivatives	$	40	$	14	$	7	$	12	$	7	N/A

Liability Derivatives at June 30, 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:
Liabilities from risk management activities	$	19	$	2	$	11	$	4	$	2
Other deferred credits and liabilities	17		3		4		7		3
Total liability derivatives	$	36	$	5	$	15	$	11	$	5	N/A

At December 31, 2013, the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows:

Asset Derivatives at December 31, 2013
	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	$	16	$	5	$	3	$	5	$	3
Other deferred charges and assets	7		2		2		2		2
Total derivatives designated as hedging instruments for regulatory purposes	$	23	$	7	$	5	$	7	$	5	N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current assets	3		—		—		—		—		$	—
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other deferred charges and assets	1		—		—		—		—		1
Total asset derivatives	$	27	$	7	$	5	$	7	$	5	$	1

Liability Derivatives at December 31, 2013
	Fair Value
Derivative Category and Balance Sheet Location	Southern Company		Alabama Power		Georgia Power		Gulf Power		Mississippi Power		Southern Power
	(in millions)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Liabilities from risk management activities	$	26	$	3	$	13	$	6	$	4
Other deferred credits and liabilities	29		5		8		11		6
Total derivatives designated as hedging instruments for regulatory purposes	$	55	$	8	$	21	$	17	$	10	N/A
Derivatives not designated as hedging instruments
Energy-related derivatives:
Liabilities from risk management activities	1		—		—		—		—		$	1
Total liability derivatives	$	56	$	8	$	21	$	17	$	10	$	1

All derivative instruments are measured at fair value. See Note (C) herein for additional information.

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 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 at June 30, 2014 and December 31, 2013 are presented in the following tables. Interest rate derivatives presented in the tables above do not have amounts available for offset and are therefore excluded from the offsetting disclosure tables below.

Derivative Contracts at June 30, 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)	$	40		$	14		$	7		$	12		$	7		$	—
Gross amounts not offset in the Balance Sheet (b)	(30		)	(5		)	(7		)	(8		)	(4		)	—
Net energy-related derivative assets	$	10		$	9		$	—		$	4		$	3		$	—
Liabilities
Energy-related derivatives:
Energy-related derivatives presented in the Balance Sheet (a)	$	36		$	5		$	15		$	11		$	5		$	—
Gross amounts not offset in the Balance Sheet (b)	(30		)	(5		)	(7		)	(8		)	(4		)	—
Net energy-related derivative liabilities	$	6		$	—		$	8		$	3		$	1		$	—

(a) None of the registrants offset 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, 2013
	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)	$	24		$	7		$	5		$	7		$	5		$	1
Gross amounts not offset in the Balance Sheet (b)	(22		)	(5		)	(5		)	(6		)	(4		)	—
Net energy-related derivative assets	$	2		$	2		$	—		$	1		$	1		$	1
Liabilities
Energy-related derivatives:
Energy-related derivatives presented in the Balance Sheet (a)	$	56		$	8		$	21		$	17		$	10		$	1
Gross amounts not offset in the Balance Sheet (b)	(22		)	(5		)	(5		)	(6		)	(4		)	—
Net energy-related derivative liabilities	$	34		$	3		$	16		$	11		$	6		$	1

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

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

At June 30, 2014 and December 31, 2013, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred on the balance sheets were as follows:

Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet at June 30, 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	$	(19	)	$	(2	)	$	(11	)	$	(4	)	$	(2	)
Other regulatory assets, deferred	(17		)	(3		)	(4		)	(7		)	(3		)
Other regulatory liabilities, current	31			12			6			8			5
Other regulatory liabilities, deferred	9			2			1			4			2
Total energy-related derivative gains (losses)	$	4		$	9		$	(8	)	$	1		$	2

Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet at December 31, 2013
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	$	(26	)	$	(3	)	$	(13	)	$	(6	)	$	(4	)
Other regulatory assets, deferred	(29		)	(5		)	(8		)	(11		)	(6		)
Other regulatory liabilities, current	16			5			3			5			3
Other regulatory liabilities, deferred (a)	7			2			2			2			2
Total energy-related derivative gains (losses)	$	(32	)	$	(1	)	$	(16	)	$	(10	)	$	(5	)

(a) Georgia Power includes Other regulatory liabilities, deferred in Other deferred credits and liabilities.

For the three and six months ended June 30, 2014 and 2013, the pre-tax effects of interest rate and foreign currency derivatives designated as fair value hedging instruments on the statements of income were immaterial on a gross basis for all registrants. Furthermore, the pre-tax effects of interest rate derivatives designated as fair value instruments on the statements of income were offset by changes to the carrying value of long-term debt and the pre-tax effects of foreign currency derivatives designated as fair value hedging instruments on the statements of income were offset by changes in the fair value of the purchase commitment related to equipment purchases.

For the three and six months ended June 30, 2014 and 2013, the pre-tax effects of energy-related derivatives and interest rate derivatives designated as cash flow hedging instruments recognized in OCI and those reclassified from accumulated OCI into earnings were immaterial for all registrants.

There was no material ineffectiveness recorded in earnings for any registrant for any period presented.

For the three and six months ended June 30, 2014 and 2013, the pre-tax effects of energy-related and foreign currency derivatives not designated as hedging instruments on the statements of income were immaterial for all registrants.

For Southern Power's energy-related derivatives not designated as hedging instruments, a portion of the pre-tax realized and unrealized gains and losses was associated with hedging fuel price risk of certain PPA customers and had no impact on net income or on fuel expense as presented in Southern Company's and Southern Power's statements of income for the three and six months ended June 30, 2014 and 2013. This third party hedging activity has been discontinued.

Contingent Features

The registrants do not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain Southern Company subsidiaries. At June 30, 2014, the registrants' collateral posted with their derivative counterparties was immaterial.

At June 30, 2014, the fair value of derivative liabilities with contingent features was immaterial for all registrants. The maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, were immaterial 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 - Narrative (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended	6 Months Ended
	Jun. 30, 2014	Jun. 30, 2014
Fair Value Measurements (Textual) [Abstract]
Increase (decrease) in fair value of funds including reinvested interest and dividends	$ 56	$ 83
Alabama Power [Member]
Fair Value Measurements (Textual) [Abstract]
Increase (decrease) in fair value of funds including reinvested interest and dividends	31	47
Georgia Power [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Notices Of Withdrawal Foreign Equity Funds	20.00%	20.00%
Maximum Number of Months Related to Maturities in Portfolio Not to Exceeded from Date of Purchase		13 months
Maximum Number of Days Related to Dollar Weighted Average Portfolio Maturities Regarding Commingled Funds		60 days
Commingled Funds	5	5
Fair Value Measurements (Textual) [Abstract]
Increase (decrease) in fair value of funds including reinvested interest and dividends	25	36
Minimum [Member] | Georgia Power [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Withdrawal Of Foreign Equity Fund Investment	1	1
Foreign Equity Fund Investment	$ 10	$ 10
Other - commingled funds [Member] | Georgia Power [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Maximum Number of Days Related to Dollar Weighted Average Portfolio Maturities Regarding Commingled Funds		90 days

XML

Fair Value Measurements (Tables)

6 Months Ended

Jun. 30, 2014

Fair Value Disclosures [Abstract]

Assets and liabilities measured at fair value on a recurring basis

As of June 30, 2014, 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 June 30, 2014:	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	$	—	$	40	$	—	$	40
Nuclear decommissioning trusts(a)	651		877		2		1,530
Cash equivalents	321		—		—		321
Other investments	9		—		4		13
Total	$	981	$	917	$	6	$	1,904
Liabilities:
Energy-related derivatives	$	—	$	36	$	—	$	36
Alabama Power
Assets:
Energy-related derivatives	$	—	$	14	$	—	$	14
Nuclear decommissioning trusts(b)
Domestic equity	408		81		—		489
Foreign equity	36		68		—		104
U.S. Treasury and government agency securities	—		33		—		33
Corporate bonds	—		95		—		95
Mortgage and asset backed securities	—		20		—		20
Other	—		5		2		7
Total	$	444	$	316	$	2	$	762
Liabilities:
Energy-related derivatives	$	—	$	5	$	—	$	5

	Fair Value Measurements Using
As of June 30, 2014:	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	$	—	$	7	$	—	$	7
Nuclear decommissioning trusts(b) (c)
Domestic equity	194		1		—		195
Foreign equity	—		138		—		138
U.S. Treasury and government agency securities	—		132		—		132
Municipal bonds	—		34		—		34
Corporate bonds	—		157		—		157
Mortgage and asset backed securities	—		108		—		108
Other	13		5		—		18
Total	$	207	$	582	$	—	$	789
Liabilities:
Energy-related derivatives	$	—	$	15	$	—	$	15
Gulf Power
Assets:
Energy-related derivatives	$	—	$	12	$	—	$	12
Cash equivalents	18		—		—		18
Total	$	18	$	12	$	—	$	30
Liabilities:
Energy-related derivatives	$	—	$	11	$	—	$	11
Mississippi Power
Assets:
Energy-related derivatives	$	—	$	7	$	—	$	7
Cash equivalents	205		—		—		205
Total	$	205	$	7	$	—	$	212
Liabilities:
Energy-related derivatives	$	—	$	5	$	—	$	5
Southern Power
Assets:
Cash equivalents	$	17	$	—	$	—	$	17
Total	$	17	$	—	$	—	$	17

(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, and payables related to pending investment purchases.

(c) Includes the investment securities pledged to creditors and cash collateral received and excludes payables related to the securities lending program. As of June 30, 2014, approximately $49 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 June 30, 2014, 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 June 30, 2014:	Fair Value		Unfunded Commitments	Redemption Frequency	Redemption Notice Period
	(in millions)
Southern Company
Nuclear decommissioning trusts:
Foreign equity funds	$	138	None	Monthly	5 days
Equity - commingled funds	68		None	Daily/Monthly	Daily/7 days
Other - commingled funds	5		None	Daily	Not applicable
Other - money market funds	13		None	Daily	Not applicable
Trust-owned life insurance	114		None	Daily	15 days
Cash equivalents:
Money market funds	321		None	Daily	Not applicable
Alabama Power
Nuclear decommissioning trusts:
Equity - commingled funds	$	68	None	Daily/Monthly	Daily/7 days
Trust-owned life insurance	114		None	Daily	15 days
Georgia Power
Nuclear decommissioning trusts:
Foreign equity funds	$	138	None	Monthly	5 days
Other - commingled funds	5		None	Daily	Not applicable
Other - money market funds	13		None	Daily	Not applicable
Gulf Power
Cash equivalents:
Money market funds	$	18	None	Daily	Not applicable
Mississippi Power
Cash equivalents:
Money market funds	$	205	None	Daily	Not applicable
Southern Power
Cash equivalents:
Money market funds	$	17	None	Daily	Not applicable

Financial instruments for which carrying amount did not equal fair value

As of June 30, 2014, 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	$	22,542	$	23,883
Alabama Power	$	6,229	$	6,800
Georgia Power	$	9,557	$	10,112
Gulf Power	$	1,246	$	1,306
Mississippi Power	$	2,577	$	2,571
Southern Power	$	1,629	$	1,752

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Segment and Related Information (Tables)

6 Months Ended

Jun. 30, 2014

Segment Reporting [Abstract]

Financial data for business segments

Financial data for business segments and products and services for the three and six months ended June 30, 2014 and 2013 was as follows:

	Electric Utilities
	Traditional Operating Companies		Southern Power		Eliminations			Total		All Other			Eliminations			Consolidated
	(in millions)
Three Months Ended June 30, 2014:
Operating revenues	$	4,209	$	329	$	(84	)	$	4,454	$	39		$	(26	)	$	4,467
Segment net income (loss)(a)	580		31		—			611		2			(2		)	611
Six Months Ended June 30, 2014:
Operating revenues	$	8,587	$	680	$	(186	)	$	9,081	$	80		$	(50	)	$	9,111
Segment net income (loss)(a)(c)	899		64		—			963		2			(3		)	962
Total assets at June 30, 2014	$	61,210	$	4,605	$	(132	)	$	65,683	$	1,356		$	(639	)	$	66,400
Three Months Ended June 30, 2013:
Operating revenues	$	4,018	$	307	$	(95	)	$	4,230	$	38		$	(22	)	$	4,246
Segment net income (loss)(a)(b)	268		28		—			296		4			(3		)	297
Six Months Ended June 30, 2013:
Operating revenues	$	7,687	$	610	$	(181	)	$	8,116	$	73		$	(46	)	$	8,143
Segment net income (loss)(a)(c)	334		57		—			391		(12		)	(1		)	378
Total assets at December 31, 2013	$	59,447	$	4,429	$	(101	)	$	63,775	$	1,077		$	(306	)	$	64,546

(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 June 30, 2013 includes a $450.0 million pre-tax charge ($277.9 million after tax) for an estimated probable loss on the Kemper IGCC. See Note (B) under "Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" herein for additional information.

(c) Segment net income (loss) for the traditional operating companies for the six months ended June 30, 2014 and June 30, 2013 includes $380.0 million in pre-tax charges ($234.7 million after tax) and $990.0 million in pre-tax charges ($611.3 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 June 30, 2014	$	3,770	$	515	$	169	$	4,454
Three Months Ended June 30, 2013	3,620		454		156		4,230
Six Months Ended June 30, 2014	$	7,628	$	1,119	$	334	$	9,081
Six Months Ended June 30, 2013	6,918		886		312		8,116

XML

Derivatives - Schedule of Derivatives and Gains (Losses) (Details) (USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2014
Alabama Power [Member]
Notional amount of interest rate derivatives
Notional Amount	$ 75
Fair Value Hedging [Member] | Alabama Power [Member]
Notional amount of interest rate derivatives
Interest Rate Received	3-month LIBOR
Weighted Average Interest Rate Paid	3.12108%
Hedge Maturity Date	Oct. 01, 2025
Fair Value Gain (Loss) June 30, 2014	$ 0
Gas [Member] | Southern Company [Member]
Energy-related derivative contracts
Net Purchased mmBtu	250,000,000
Longest Hedge Date	2018
Longest Non-hedge Date	2017
Gas [Member] | Alabama Power [Member]
Energy-related derivative contracts
Net Purchased mmBtu	63,000,000
Longest Hedge Date	2017
Gas [Member] | Georgia Power [Member]
Energy-related derivative contracts
Net Purchased mmBtu	50,000,000
Longest Hedge Date	2017
Gas [Member] | Gulf Power [Member]
Energy-related derivative contracts
Net Purchased mmBtu	85,000,000
Longest Hedge Date	2018
Gas [Member] | Mississippi Power [Member]
Energy-related derivative contracts
Net Purchased mmBtu	51,000,000
Longest Hedge Date	2017
Gas [Member] | Southern Power [Member]
Energy-related derivative contracts
Net Purchased mmBtu	1,000,000
Longest Non-hedge Date	2017

XML

Condensed Consolidated Statements of Cash Flows (Unaudited) (USD $)	6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013
Southern Company [Member]
Operating Activities:
Consolidated net income	$ 996,000,000	$ 410,000,000
Adjustments to reconcile consolidated net income to net cash provided from operating activities --
Depreciation and amortization, total	1,182,000,000	1,140,000,000
Deferred income taxes	46,000,000	(141,000,000)
Allowance for equity funds used during construction	(119,000,000)	(86,000,000)
Stock based compensation expense	40,000,000	37,000,000
Estimated loss on Kemper IGCC	380,000,000	990,000,000
Other, net	22,000,000	48,000,000
Changes in certain current assets and liabilities --
-Receivables	(579,000,000)	(325,000,000)
-Fossil fuel stock	419,000,000	185,000,000
-Materials and supplies	(20,000,000)	52,000,000
-Other current assets	(88,000,000)	(55,000,000)
-Accounts payable	(231,000,000)	(52,000,000)
-Accrued taxes	72,000,000	6,000,000
-Accrued compensation	(40,000,000)	(257,000,000)
-Other current liabilities	(10,000,000)	(5,000,000)
Net cash provided from operating activities	2,070,000,000	1,947,000,000
Investing Activities:
Property additions	(2,692,000,000)	(2,597,000,000)
Investment of restricted cash	0	(98,000,000)
Distribution of restricted cash	11,000,000	23,000,000
Nuclear decommissioning trust fund purchases	(445,000,000)	(548,000,000)
Nuclear decommissioning trust fund sales	443,000,000	546,000,000
Cost of removal, net of salvage	(54,000,000)	(56,000,000)
Change in construction payables	89,000,000	114,000,000
Prepaid long-term service agreement	(93,000,000)	(57,000,000)
Other investing activities	(28,000,000)	44,000,000
Net cash used for investing activities	(2,769,000,000)	(2,629,000,000)
Financing Activities:
Increase (decrease) in notes payable, net	339,000,000	767,000,000
Proceeds --
Long-term debt issuances	1,314,000,000	1,197,000,000
Interest-bearing refundable deposit related to asset sale	75,000,000	0
Preference stock	0	50,000,000
Common stock issuances	318,000,000	161,000,000
Redemptions --
Long-term debt	(431,000,000)	(792,000,000)
Common stock repurchased	(5,000,000)	(18,000,000)
Payment of common stock dividends	(920,000,000)	(870,000,000)
Payment of dividends on preferred and preference stock of subsidiaries	(34,000,000)	(32,000,000)
Other financing activities	(33,000,000)	15,000,000
Net cash provided from (used for) financing activities	623,000,000	478,000,000
Net Change in Cash and Cash Equivalents	(76,000,000)	(204,000,000)
Cash and Cash Equivalents at Beginning of Period	659,000,000	628,000,000
Cash and Cash Equivalents at End of Period	583,000,000	424,000,000
Cash paid (received) during the period for --
Interest (net of capitalized amounts)	365,000,000	384,000,000
Income taxes, net	212,000,000	142,000,000
Noncash transactions - accrued property additions at end of period	509,000,000	637,000,000
Alabama Power [Member]
Operating Activities:
Consolidated net income	380,000,000	334,000,000
Adjustments to reconcile consolidated net income to net cash provided from operating activities --
Depreciation and amortization, total	416,000,000	403,000,000
Deferred income taxes	49,000,000	53,000,000
Allowance for equity funds used during construction	(21,000,000)	(16,000,000)
Regulatory deferrals	(44,000,000)	(9,000,000)
Other, net	4,000,000	(3,000,000)
Changes in certain current assets and liabilities --
-Receivables	(120,000,000)	(65,000,000)
-Fossil fuel stock	94,000,000	76,000,000
-Materials and supplies	(2,000,000)	22,000,000
-Other current assets	(57,000,000)	(45,000,000)
-Accounts payable	(94,000,000)	(93,000,000)
-Accrued taxes	104,000,000	60,000,000
-Accrued compensation	(17,000,000)	(54,000,000)
-Retail fuel cost over recovery - short-term	(23,000,000)	12,000,000
-Other current liabilities	5,000,000	4,000,000
Net cash provided from operating activities	674,000,000	679,000,000
Investing Activities:
Property additions	(637,000,000)	(518,000,000)
Nuclear decommissioning trust fund purchases	(121,000,000)	(120,000,000)
Nuclear decommissioning trust fund sales	121,000,000	120,000,000
Cost of removal, net of salvage	(30,000,000)	(19,000,000)
Change in construction payables	71,000,000	(21,000,000)
Other investing activities	(13,000,000)	30,000,000
Net cash used for investing activities	(609,000,000)	(528,000,000)
Financing Activities:
Increase (decrease) in notes payable, net	27,000,000	46,000,000
Proceeds --
Capital contributions from parent company	12,000,000	10,000,000
Redemptions --
Payment of preferred and preference stock dividends	(20,000,000)	(20,000,000)
Payment of common stock dividends	(275,000,000)	(265,000,000)
Other financing activities	1,000,000	0
Net cash provided from (used for) financing activities	(255,000,000)	(229,000,000)
Net Change in Cash and Cash Equivalents	(190,000,000)	(78,000,000)
Cash and Cash Equivalents at Beginning of Period	295,000,000	137,000,000
Cash and Cash Equivalents at End of Period	105,000,000	59,000,000
Cash paid (received) during the period for --
Interest (net of capitalized amounts)	114,000,000	119,000,000
Income taxes, net	141,000,000	146,000,000
Noncash transactions - accrued property additions at end of period	89,000,000	10,000,000
Georgia Power [Member]
Operating Activities:
Consolidated net income	586,000,000	488,000,000
Adjustments to reconcile consolidated net income to net cash provided from operating activities --
Depreciation and amortization, total	503,000,000	487,000,000
Deferred income taxes	121,000,000	126,000,000
Allowance for equity funds used during construction	(16,000,000)	(13,000,000)
Retail fuel cost over recovery - long-term	(44,000,000)	(123,000,000)
Deferred expenses	31,000,000	31,000,000
Other, net	(12,000,000)	(8,000,000)
Changes in certain current assets and liabilities --
-Receivables	(353,000,000)	(123,000,000)
-Fossil fuel stock	255,000,000	56,000,000
-Prepaid income taxes	(7,000,000)	5,000,000
-Other current assets	(14,000,000)	34,000,000
-Accounts payable	(140,000,000)	43,000,000
-Accrued taxes	(65,000,000)	(14,000,000)
-Accrued compensation	(15,000,000)	(66,000,000)
-Retail fuel cost over recovery - short-term	(14,000,000)	1,000,000
-Other current liabilities	27,000,000	7,000,000
Net cash provided from operating activities	843,000,000	931,000,000
Investing Activities:
Property additions	(906,000,000)	(765,000,000)
Investment of restricted cash	0	(18,000,000)
Distribution of restricted cash	0	18,000,000
Nuclear decommissioning trust fund purchases	(324,000,000)	(427,000,000)
Nuclear decommissioning trust fund sales	322,000,000	426,000,000
Cost of removal, net of salvage	(12,000,000)	(27,000,000)
Prepaid long-term service agreement	(47,000,000)	(9,000,000)
Change in construction payables, net of joint owner portion	52,000,000	(2,000,000)
Other investing activities	(2,000,000)	(3,000,000)
Net cash used for investing activities	(917,000,000)	(807,000,000)
Financing Activities:
Increase (decrease) in notes payable, net	(359,000,000)	314,000,000
Proceeds --
Capital contributions from parent company	24,000,000	21,000,000
Pollution control revenue bonds issuances	0	18,000,000
Senior notes issuances	0	650,000,000
FFB loan	1,000,000,000	0
Redemptions --
Pollution control revenue bonds	(37,000,000)	(18,000,000)
Senior notes	0	(650,000,000)
Payment of preferred and preference stock dividends	(9,000,000)	(9,000,000)
Payment of common stock dividends	(477,000,000)	(454,000,000)
FFB loan issuance costs	(49,000,000)	(1,000,000)
Other financing activities	(3,000,000)	(11,000,000)
Net cash provided from (used for) financing activities	90,000,000	(140,000,000)
Net Change in Cash and Cash Equivalents	16,000,000	(16,000,000)
Cash and Cash Equivalents at Beginning of Period	30,000,000	45,000,000
Cash and Cash Equivalents at End of Period	46,000,000	29,000,000
Cash paid (received) during the period for --
Interest (net of capitalized amounts)	157,000,000	169,000,000
Income taxes, net	145,000,000	100,000,000
Noncash transactions - accrued property additions at end of period	267,000,000	238,000,000
Gulf Power [Member]
Operating Activities:
Consolidated net income	75,341,000	57,576,000
Adjustments to reconcile consolidated net income to net cash provided from operating activities --
Depreciation and amortization, total	74,689,000	77,627,000
Deferred income taxes	19,627,000	36,407,000
Allowance for equity funds used during construction	(5,081,000)	(2,655,000)
Pension, postretirement, and other employee benefits	2,851,000	5,452,000
Stock based compensation expense	1,111,000	1,028,000
Other, net	(3,396,000)	2,209,000
Changes in certain current assets and liabilities --
-Receivables	(56,873,000)	(59,770,000)
-Prepayments	1,463,000	1,271,000
-Fossil fuel stock	39,187,000	19,332,000
-Materials and supplies	1,170,000	(987,000)
-Prepaid income taxes	9,289,000	(2,822,000)
-Other current assets	(1,024,000)	13,000
-Accounts payable	831,000	(9,703,000)
-Accrued taxes	12,483,000	13,632,000
-Accrued compensation	(109,000)	(8,308,000)
-Over recovered regulatory clause revenues	9,129,000	(15,659,000)
-Other current liabilities	(3,522,000)	(1,199,000)
Net cash provided from operating activities	177,166,000	113,444,000
Investing Activities:
Property additions	(158,863,000)	(137,283,000)
Cost of removal, net of salvage	(6,032,000)	(7,010,000)
Change in construction payables	(1,684,000)	6,307,000
Payments pursuant to long-term service agreements	(3,953,000)	(2,855,000)
Other investing activities	46,000	120,000
Net cash used for investing activities	(170,486,000)	(140,721,000)
Financing Activities:
Increase (decrease) in notes payable, net	2,702,000	1,230,000
Proceeds --
Capital contributions from parent company	2,268,000	1,419,000
Pollution control revenue bonds issuances	42,075,000	63,000,000
Preference stock	0	50,000,000
Common stock issuances	50,000,000	40,000,000
Senior notes issuances	0	90,000,000
Redemptions --
Pollution control revenue bonds	(29,075,000)	(63,000,000)
Payment of preferred and preference stock dividends	(4,501,000)	(3,101,000)
Payment of common stock dividends	(61,600,000)	(57,700,000)
Other financing activities	(602,000)	(3,105,000)
Net cash provided from (used for) financing activities	1,267,000	118,743,000
Net Change in Cash and Cash Equivalents	7,947,000	91,466,000
Cash and Cash Equivalents at Beginning of Period	21,753,000	32,167,000
Cash and Cash Equivalents at End of Period	29,700,000	123,633,000
Cash paid (received) during the period for --
Interest (net of capitalized amounts)	25,860,000	26,987,000
Income taxes, net	16,712,000	428,000
Noncash transactions - accrued property additions at end of period	30,951,000	29,036,000
Mississippi Power [Member]
Operating Activities:
Consolidated net income	(108,687,000)	(464,565,000)
Adjustments to reconcile consolidated net income to net cash provided from operating activities --
Depreciation and amortization, total	49,869,000	43,263,000
Deferred income taxes	(107,556,000)	(337,167,000)
Investment tax credits	27,750,000	66,474,000
Allowance for equity funds used during construction	(75,462,000)	(55,116,000)
Pension, postretirement, and other employee benefits	2,551,000	6,184,000
Stock based compensation expense	1,878,000	1,547,000
Regulatory assets associated with Kemper IGCC	(26,091,000)	(13,399,000)
Estimated loss on Kemper IGCC	380,000,000	912,000,000
Kemper regulatory deferral	67,125,000	26,979,000
Other, net	2,266,000	1,068,000
Changes in certain current assets and liabilities --
-Receivables	(11,972,000)	(37,431,000)
-Under recovered regulatory clause revenues	(19,842,000)	0
-Fossil fuel stock	31,707,000	34,205,000
-Materials and supplies	(5,607,000)	(6,509,000)
-Prepaid income taxes	(12,261,000)	8,823,000
-Other current assets	1,063,000	(4,879,000)
-Accounts payable	4,424,000	(5,417,000)
-Accrued taxes	(22,513,000)	(24,101,000)
-Accrued interest	13,256,000	8,502,000
-Accrued compensation	3,634,000	(10,461,000)
-Over recovered regulatory clause revenues	(18,358,000)	(27,838,000)
-Other current liabilities	1,031,000	282,000
Net cash provided from operating activities	178,205,000	122,444,000
Investing Activities:
Property additions	(691,859,000)	(789,021,000)
Cost of removal, net of salvage	(5,358,000)	(2,033,000)
Change in construction payables	(28,326,000)	23,314,000
Capital grant proceeds	0	4,500,000
Other investing activities	(7,920,000)	(11,172,000)
Net cash used for investing activities	(733,463,000)	(774,412,000)
Proceeds --
Capital contributions from parent company	211,027,000	351,198,000
Bonds-Other	12,318,000	15,814,000
Interest-bearing refundable deposit related to asset sale	75,000,000	0
Long-term debt issuance from parent company	220,000,000	0
Other long-term debt issuances	250,000,000	350,000,000
Redemptions — Capital leases	(1,254,000)	0
Redemptions --
Payment of preferred and preference stock dividends	(866,000)	(866,000)
Payment of common stock dividends	0	(71,956,000)
Return of capital	(109,860,000)	(16,424,000)
Other financing activities	(381,000)	(1,431,000)
Net cash provided from (used for) financing activities	655,984,000	626,335,000
Net Change in Cash and Cash Equivalents	100,726,000	(25,633,000)
Cash and Cash Equivalents at Beginning of Period	145,165,000	145,008,000
Cash and Cash Equivalents at End of Period	245,891,000	119,375,000
Cash paid (received) during the period for --
Interest (net of capitalized amounts)	8,349,000	13,423,000
Income taxes, net	(33,621,000)	(64,062,000)
Noncash transactions - accrued property additions at end of period	135,675,000	238,177,000
Southern Power [Member]
Operating Activities:
Consolidated net income	66,330,000	57,114,000
Adjustments to reconcile consolidated net income to net cash provided from operating activities --
Depreciation and amortization, total	100,111,000	90,351,000
Deferred income taxes	(3,162,000)	13,693,000
Investment tax credits	26,134,000	16,443,000
Deferred revenues	(24,342,000)	(23,444,000)
Other, net	7,893,000	11,909,000
Changes in certain current assets and liabilities --
-Receivables	(34,252,000)	(23,335,000)
-Fossil fuel stock	(1,006,000)	(377,000)
-Materials and supplies	(3,126,000)	(2,560,000)
-Prepaid income taxes	21,406,000	(19,747,000)
-Other current assets	2,051,000	2,725,000
-Accounts payable	23,593,000	(7,580,000)
-Accrued taxes	7,095,000	21,048,000
-Accrued interest	94,000	(41,000)
-Other current liabilities	5,027,000	(390,000)
Net cash provided from operating activities	193,846,000	135,809,000
Investing Activities:
Plant acquisition	(213,470,000)	(111,600,000)
Property additions	(11,048,000)	(252,271,000)
Investment of restricted cash	0	(20,000,000)
Change in construction payables	(3,426,000)	106,795,000
Payments pursuant to long-term service agreements	(22,677,000)	(22,469,000)
Other investing activities	(10,860,000)	(206,000)
Net cash used for investing activities	(261,481,000)	(299,751,000)
Financing Activities:
Increase (decrease) in notes payable, net	73,482,000	195,142,000
Proceeds --
Capital contributions from parent company	(3,417,000)	1,394,000
Other long-term debt issuances	9,941,000	10,249,000
Redemptions --
Other long-term debt	(818,000)	(220,000)
Distributions to noncontrolling interest	(150,000)	(146,000)
Contributions from noncontrolling interest	7,166,000	7,683,000
Payment of common stock dividends	(65,560,000)	(64,560,000)
Other financing activities	1,863,000	675,000
Net cash provided from (used for) financing activities	22,507,000	150,217,000
Net Change in Cash and Cash Equivalents	(45,128,000)	(13,725,000)
Cash and Cash Equivalents at Beginning of Period	68,744,000	28,592,000
Cash and Cash Equivalents at End of Period	23,616,000	14,867,000
Cash paid (received) during the period for --
Interest (net of capitalized amounts)	42,745,000	34,924,000
Income taxes, net	(59,148,000)	(3,799,000)
Noncash transactions - accrued property additions at end of period	$ 5,297,000	$ 136,998,000

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Contingencies and Regulatory Matters

6 Months Ended

Jun. 30, 2014

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 increased generally throughout the U.S. In particular, personal injury, property damage, and other claims for damages alleged to have been caused by CO₂ and other emissions, coal combustion residuals, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters, have become more frequent.

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 September 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 June 30, 2014 was $19 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 February 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. In May 2013, the plaintiffs appealed the U.S. District Court for the Eastern District of North Carolina Western Division's order to the U.S. Court of Appeals for the Fourth Circuit.

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 $50 million as of June 30, 2014. 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, there was no impact on net income as a result of these liabilities.

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 December 2013 and, on March 28, 2014, the impacted utilities, including Mississippi Power, agreed to commence remediation actions on the site. Mississippi Power's environmental remediation liability is $0.6 million as of June 30, 2014 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 have pursued and continue to pursue legal remedies against the U.S. government for its partial breach of contract.

As a result of the first lawsuit, Georgia Power recovered approximately $27 million, based on its ownership interests, and Alabama Power recovered approximately $17 million, representing the vast majority of the Southern Company system's direct costs of the expansion of spent nuclear fuel storage facilities at Plants Farley and Hatch and Plant Vogtle Units 1 and 2 from 1998 through 2004. In 2012, Alabama Power credited the award to cost of service for the benefit of customers. Also in 2012, Georgia Power credited the award to accounts where the original costs were charged and used it to reduce rate base, fuel, and cost of service for the benefit of customers.

In 2008 and again on March 4, 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, 2005 through December 31, 2010 and from January 1, 2011 through December 31, 2013, respectively. Damages will continue to accumulate until the issue is resolved or storage is provided. 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.

An on-site dry storage facility at Plant Vogtle Units 1 and 2 began operation in October 2013. At Plants Hatch and Farley, on-site dry spent fuel storage facilities are also operational. Facilities at all plants can be expanded to accommodate spent fuel through the expected life of each plant.

FERC Matters

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 the authority to defer in a regulatory asset costs related to the retirement or partial retirement of generating units as a result of environmental compliance rules. See Note 3 to the financial statements of Southern Company under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K, Note 3 to the financial statements of 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, 2014, Mississippi Power reached a settlement agreement with its wholesale customers and filed a request with the FERC for an increase in the Municipal and Rural Associations (MRA) cost-based electric tariff. The settlement agreement, approved by the FERC on May 20, 2014, provides that base rates under the MRA cost-based electric tariff will increase approximately $10.1 million annually, with revised rates effective for services rendered beginning May 1, 2014. The amount of base rate revenues to be received in 2014 from the agreed upon increase is expected to be approximately $6.9 million.

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	June 30, 2014		December 31, 2013
		(in millions)
Rate CNP Environmental – Under	Deferred under recovered regulatory clause revenues	$	32	$	7
Rate CNP PPA – Under	Deferred under recovered regulatory clause revenues	33		18
Retail Energy Cost Recovery – Over	Other regulatory liabilities, current	19		27
	Deferred over recovered regulatory clause revenues	—		15
Natural Disaster Reserve	Other regulatory liabilities, deferred	87		96

Georgia Power

Renewables Development

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

On May 20, 2014, the Georgia PSC approved Georgia Power's application for the certification of two PPAs executed in April 2013 for the purchase of energy from two wind farms in Oklahoma with capacity totaling 250 MWs that will begin in 2016 and end in 2035.

As a result of amendments executed subsequent to June 30, 2014, the biomass PPAs classified as non-affiliate capital leases with related long-term obligations totaling $641 million as of December 31, 2013, no longer meet the definition of a lease or will be accounted for as operating leases. Due to these amendments, non-affiliate operating lease obligations increased by $127 million. As a result of additional amendmentsexecuted prior to June 30, 2014, commitments related to non-affiliate operating leases increased by a total of $23 million. As such, estimated total long-term obligations for non-affiliate operating leases have been updated to $116 million for 2015, $149 million for 2016, $150 million for 2017, $152 million for 2018 and $1.7 billion for 2019 and thereafter. Estimated long-term obligations did not change for 2014. The counterparties of the aforementioned PPAs have posted collateral as required. See Note 7 to the financial statements of Georgia Power under "Commitments – Fuel and Purchased Power Agreements" in Item 8 of the Form 10-K for additional information.

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.

Georgia Power filed a request with the Georgia PSC on January 10, 2014 to cancel the proposed biomass fuel conversion of Plant Mitchell Unit 3 (155 MWs) because it would not be cost effective for customers. On July 1, 2014, the Georgia PSC approved Georgia Power's request. The January 10, 2014 filing also notified the Georgia PSC of Georgia Power's plan to seek decertification later this year. Georgia Power now expects to request decertification of Plant Mitchell Unit 3 in connection with the triennial Integrated Resource Plan in 2016. Georgia Power plans to continue to operate the unit as needed until the Mercury and Air Toxics Standards rule becomes effective in April 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 June 30, 2014, Georgia Power's under recovered fuel balance totaled $244 million and is included in deferred charges and other assets on Southern Company's and Georgia Power's Condensed Balance Sheets herein. The under recovered fuel balance exceeded the $200 million threshold, triggering the Interim Fuel Rider mechanism. Therefore, on July 7, 2014, Georgia Power filed a plan with the Georgia PSC recommending that the Georgia PSC defer any action on the under recovered fuel balance until the next fuel case which is expected to be filed by February 27, 2015. The Georgia PSC took no action on Georgia Power's filing within 30 days; therefore, the existing fuel rates remain in place. As of December 31, 2013, Georgia Power's over recovered fuel balance totaled $58 million and is included in current liabilities and other deferred credits and liabilities on Southern Company's and Georgia Power's Condensed Balance Sheets herein.

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.

Storm Damage Recovery

See Note 1 to the financial statements of Georgia Power under "Storm Damage Recovery" in Item 8 of the Form 10-K for additional information.

Georgia Power defers and recovers certain costs related to damages from major storms as mandated by the Georgia PSC. As of June 30, 2014 and December 31, 2013, the balance in the regulatory asset related to storm damage was $107 million and $37 million, respectively.

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, the eighth Vogtle Construction Monitoring (VCM) report, the ninth/tenth VCM report, and pending litigation.

In 2008, Georgia Power, acting for itself and as agent for the 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 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. Each 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%. The Vogtle 3 and 4 Agreement provides for liquidated damages upon the Contractor's failure to fulfill the schedule and performance guarantees. The Contractor's liability to the Owners for schedule and performance liquidated damages and warranty claims is subject to a cap.

Certain payment obligations of Westinghouse and Stone & Webster, Inc. under the Vogtle 3 and 4 Agreement are guaranteed by Toshiba Corporation and The Shaw Group, Inc., respectively. In the event of certain credit rating downgrades of any Owner, such Owner will be required to provide a letter of credit or other credit enhancement. The Owners may terminate the Vogtle 3 and 4 Agreement at any time for their convenience, provided that the Owners will be required to pay certain termination costs. The Contractor may terminate the Vogtle 3 and 4 Agreement under certain circumstances, including certain 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 Owners, 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 2009, the Georgia PSC approved inclusion of the Plant Vogtle Units 3 and 4 related CWIP accounts in rate base, and the State of Georgia enacted the Georgia Nuclear Energy Financing Act, which allows Georgia Power to recover financing costs for nuclear construction projects certified by the Georgia PSC. Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff by including the related CWIP accounts in rate base during the construction period. The Georgia PSC approved increases to the NCCR tariff of approximately $223 million, $35 million, $50 million, and $60 million, effective January 1, 2011, 2012, 2013, and 2014, respectively. Through the NCCR tariff, Georgia Power is collecting and amortizing to earnings approximately $91 million of financing costs, capitalized in 2009 and 2010, over the five-year period ending December 31, 2015, in addition to the ongoing financing costs. At June 30, 2014, approximately $27 million of these 2009 and 2010 costs remained unamortized in CWIP.

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. Accordingly, Georgia Power's eighth VCM report filed in February 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 September 2013, the Georgia PSC approved a 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. In accordance with the Georgia Integrated Resource Planning Act, any costs incurred by Georgia Power in excess of the certified amount will not be included in rate base, unless shown to be reasonable and prudent. In addition, financing costs on any excess construction-related costs potentially would be subject to recovery through AFUDC instead of the NCCR tariff. In accordance with the stipulation, Georgia Power filed with the Georgia PSC on February 28, 2014 a combined ninth and tenth VCM report covering the period from January 1 through December 31, 2013 (Ninth/Tenth VCM report), which requested approval for an additional $0.4 billion of construction capital costs. The Ninth/Tenth VCM report reflects estimated in-service construction capital costs of $4.8 billion and associated financing costs during the construction period, which are estimated to total approximately $2.0 billion. Georgia Power will resume filing semi-annual reports with the eleventh VCM report filing in late August 2014.

In 2012, the 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 Owners are responsible for these costs under the terms of the Vogtle 3 and 4 Agreement. Also in 2012, Georgia Power and the other Owners filed suit against the Contractor in the U.S. District Court for the Southern District of Georgia seeking a declaratory judgment that the Owners are not responsible for these costs. Later in 2012, the Contractor filed suit against Georgia Power and the other Owners in the U.S. District Court for the District of Columbia alleging the Owners are responsible for these costs. In August 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. The Contractor appealed the decision to the U.S. Court of Appeals for the District of Columbia Circuit in September 2013. 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 has asserted it is entitled to further schedule extensions. On May 22, 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 have 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 claimed amounts relating to these new allegations, but such additional claimed amounts could be substantial. Georgia Power has not agreed with either the proposed cost or schedule adjustments or that the Owners have any responsibility for costs related to these issues. While litigation is ongoing and Georgia Power intends to vigorously defend its positions, Georgia Power also expects negotiations with the Contractor to continue with respect to cost and schedule during which negotiations the parties may reach a mutually acceptable compromise of their positions.

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 Owners or the Contractor or to both.

As construction continues, the risk remains that additional challenges in the 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. Additional claims by the Contractor or Georgia Power (on behalf of the 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 $5.4 million reduction in depreciation expense in the first six months of 2014.

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	June 30, 2014		December 31, 2013
		(in millions)
Fuel Cost Recovery – Under	Under recovered regulatory clause revenues	$	43.4	$	21.0
Purchased Power Capacity Recovery – Over	Other regulatory liabilities, current	9.1		—
Purchased Power Capacity Recovery – Under	Under recovered regulatory clause revenues	—		2.8
Environmental Cost Recovery – Under	Under recovered regulatory clause revenues	15.1		14.4
Energy Conservation Cost Recovery – Under	Under recovered regulatory clause revenues	4.9		7.0

Retail Fuel Cost Recovery

See Note 1 and Note 3 to the financial statements of Gulf Power under "Revenues" and "Retail Regulatory Matters – Fuel Cost Recovery," respectively, in Item 8 of the Form 10-K for additional information.

Gulf Power has established fuel cost recovery rates as approved annually by the Florida PSC. In late 2013 and the first six months of 2014, Gulf Power experienced higher than expected costs for natural gas and purchased power along with lower fuel revenues for non-territorial sales. If the projected year-end fuel cost over or under recovery balance exceeds 10% of the projected fuel revenues for the period, Gulf Power is required to notify the Florida PSC and indicate if an adjustment to the fuel recovery factor is being requested. Gulf Power filed such notice with the Florida PSC on July 18, 2014, but no adjustment to the factor was requested. Under recovered fuel costs at June 30, 2014 totaled $43.4 million and are included in under recovered regulatory clause revenues on Gulf Power's Condensed Balance Sheet herein. Fuel cost recovery revenues, as recorded on the financial statements, are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, any changes in the billing factor would have no significant effect on Gulf Power's revenues or net income, but will affect cash flow.

Mississippi Power

Energy Efficiency

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

On June 3, 2014, the Mississippi PSC approved Mississippi Power's 2014 Energy Efficiency Quick Start Plan filing, which includes a portfolio of energy efficiency programs. On June 24, 2014, Mississippi Power submitted the 2014 Energy Efficiency Cost Recovery filing, which proposed an increase of $1.5 million in annual retail revenues to recover costs associated with energy efficiency programs. On July 21, 2014, the Mississippi PSC suspended the filing to allow more time for review.

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

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 18, 2014, Mississippi Power submitted its annual PEP lookback filing for 2013, which indicated no surcharge or refund. On March 31, 2014, the Mississippi PSC suspended the filing to allow more time for review.

On June 3, 2014, the Mississippi PSC issued an order for the purpose of investigating and reviewing the adoption of a uniform formula rate plan for Mississippi Power and other regulated electric utilities in Mississippi.

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

System Restoration Rider

See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – System Restoration Rider" in Item 8 of the Form 10-K for additional information.

On April 1, 2014, the Mississippi PSC approved Mississippi Power's request to continue a zero System Restoration Rider rate for 2014 and to accrue approximately $3.3 million to the property damage reserve in 2014.

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 a scrubber on Plant Daniel Units 1 and 2. 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. The project is scheduled for completion in December 2015. 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 June 30, 2014, total project expenditures were $419.6 million, of which Mississippi Power's portion was $213.7 million, excluding AFUDC of $13.3 million.

On August 1, 2014, Mississippi Power entered into a settlement agreement with the Sierra Club (Sierra Club Settlement Agreement) that, among other things, requires the Sierra Club to dismiss or withdraw all pending legal and regulatory challenges to the issuance of the CPCN to construct a scrubber on Plant Daniel Units 1 and 2. In addition, and consistent with Mississippi Power's ongoing evaluation of recent environmental rules and regulations, Mississippi Power agreed to retire, repower with natural gas, or convert to an alternative non-fossil fuel source Plant Sweatt Units 1 and 2 (80 MWs) no later than December 2018. Mississippi Power also agreed that it would cease burning coal and other solid fuel at Plant Watson Units 4 and 5 (750 MWs) and begin operating those units solely on natural gas no later than April 2015, and cease burning coal and other solid fuel at Plant Greene County Units 1 and 2 (200 MWs) and begin operating those units solely on natural gas no later than April 2016. On August 4, 2014, Mississippi Power, the Sierra Club, and the Mississippi PSC filed a joint motion to dismiss the appeal related to the CPCN to construct a scrubber on Plant Daniel Units 1 and 2.

In accordance with a 2011 accounting order from the Mississippi PSC, Mississippi Power has the authority to defer in a regulatory asset for future recovery all plant retirement- or partial retirement-related costs resulting from environmental regulations. Approved regulatory asset costs will be amortized over a period to be determined by the Mississippi PSC. As a result, these decisions are not expected to have a material impact on Southern Company's and Mississippi Power's financial statements. See "Other Matters – Sierra Club Settlement Agreement" herein for additional information.

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 June 30, 2014, the amount of under recovered retail fuel costs included on Mississippi Power's Condensed Balance Sheet herein was $14.5 million compared to over recovered retail fuel costs of $14.5 million at December 31, 2013.

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 May 6, 2014, the Mississippi PSC approved Mississippi Power's annual ad valorem tax adjustment factor filing for 2014, which requested an annual rate increase of 0.38%, or $3.6 million in annual retail revenues, primarily due to an increase in property tax rates.

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 Project Approval

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, which the Sierra Club appealed to the Chancery Court. Later in 2012, the Chancery Court affirmed the 2012 MPSC CPCN Order. In January 2013, the Sierra Club filed an appeal of the Chancery Court's ruling with the Mississippi Supreme Court.

On August 1, 2014, Mississippi Power entered into the Sierra Club Settlement Agreement that, among other things, requires the Sierra Club to dismiss or withdraw all pending legal and regulatory challenges against the Kemper IGCC, including the appeal to the Mississippi Supreme Court related to the 2012 MPSC CPCN. On August 4, 2014, Mississippi Power and the Sierra Club filed a joint motion to dismiss the appeal related to the 2012 MPSC CPCN. Also on August 4, 2014, Thomas A. Blanton, who is not a party to the CPCN appeal, filed a motion to stay the motion to dismiss. See "Other Matters – Sierra Club Settlement Agreement" herein for additional information.

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

Kemper IGCC Schedule and Cost Estimate

The certificated cost estimate of the Kemper IGCC included in the 2012 MPSC CPCN Order was $2.4 billion, net of $245.3 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. Exceptions to the $2.88 billion cost cap include 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), as contemplated in the 2013 Settlement Agreement (defined below) and the 2012 MPSC CPCN Order. Recovery of the Cost Cap Exception amounts remains subject to review and approval by the Mississippi PSC.

The Kemper IGCC was originally scheduled to be placed in service in May 2014. Mississippi Power currently expects to place the combined cycle and the associated common facilities portion of the Kemper IGCC in service in the summer of 2014 and continues to focus on completing the remainder of the Kemper IGCC, including the gasification system, for which the in-service date is currently expected to occur in the second quarter 2015. On August 5, 2014, the Mississippi PSC ordered Mississippi Power to provide an analysis of the costs and benefits of placing the combined cycle and the associated common facilities portion of the Kemper IGCC in service in the summer of 2014 and to identify any expected or necessary accounting treatment and/or potential adjustments or impacts related to revenue recognition or any regulatory liability accounts.

Mississippi Power's 2010 project estimate, current cost estimate, and actual costs incurred as of June 30, 2014 for the Kemper IGCC are as follows:

Cost Category	2010 Project Estimate(e)		Current Estimate		Actual Costs at June 30, 2014
	(in billions)
Plant Subject to Cost Cap(a)	$	2.40	$	4.44	$	3.81
Lignite Mine and Equipment	0.21		0.24		0.23
CO2 Pipeline Facilities	0.14		0.11		0.10
AFUDC(b)(c)	0.17		0.55		0.37
General Exceptions	0.05		0.10		0.07
Regulatory Asset(c)(d)	—		0.12		0.09
Total Kemper IGCC(a)(c)	$	2.97	$	5.56	$	4.67

(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.

(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."

(c) Amounts in the Current Estimate reflect costs through May 31, 2015, but do not reflect any adjustments as a result of the expected placement of the combined cycle and the associated common facilities portion of the Kemper IGCC in service in the summer of 2014.

(d) 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."

(e) 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 incurred as of June 30, 2014, $3.01 billion was included in CWIP (which is net of the DOE Grants and estimated probable losses of $1.56 billion), $97.1 million in other regulatory assets, and $3.9 million in other deferred charges and assets in Southern Company's and Mississippi Power's Condensed Balance Sheets herein, and $1.1 million was previously expensed.

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. Southern Company and Mississippi Power recorded pre-tax charges to income for revisions to the cost estimate of $380.0 million ($234.7 million after tax) in the first quarter 2014. This amount is in addition to charges totaling $1.18 billion ($728.7 million after tax) recognized through December 31, 2013. The first quarter 2014 revised cost estimate primarily reflects costs related to decreases in construction labor productivity at the Kemper IGCC identified in March 2014 due in large part to adverse weather, unexpected excessive craft labor turn-over, and unanticipated installation inefficiencies, as well as additional risk related to the expected in-service date as described herein. The revised cost estimate above includes costs through May 31, 2015. Any further extension of the in-service date is currently estimated to result in additional costs of approximately $20 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 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 performance, operational readiness, unforeseen engineering or design problems, start-up activities for this first-of-a-kind technology (including major equipment failure and system integration), and/or operations. 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 and Mississippi Power's statements of income 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 Seven-Year Rate Plan (described below) and other related proceedings during 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.

In 2012, the Mississippi PSC denied Mississippi Power's proposed rate schedule for recovery of financing costs during construction, pending a final ruling from the Mississippi Supreme Court regarding the Sierra Club's appeal of the Mississippi PSC's issuance of the CPCN for the Kemper IGCC (2012 MPSC CWIP Order). Mississippi Power appealed the Mississippi PSC's decision to the Mississippi Supreme Court and requested interim rates under bond. The Mississippi Supreme Court denied Mississippi Power's request for interim rates under bond.

2013 Settlement Agreement

In January 2013, Mississippi Power entered into a settlement agreement with the Mississippi PSC that, among other things, establishes the process for resolving matters regarding cost recovery related to the Kemper IGCC and dismissed Mississippi Power's appeal of the 2012 MPSC CWIP Order (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 allows Mississippi Power to secure alternate financing for costs that are not otherwise recovered in any Mississippi PSC rate proceedings contemplated by the 2013 Settlement Agreement. 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 February 2013. Mississippi Power intends 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 as approved by the Mississippi PSC. The rate recovery necessary to recover the annual costs of securitization is expected to be filed and become effective following completion of the Mississippi PSC's prudence review of the costs to be securitized.

The 2013 Settlement Agreement provides that Mississippi Power may terminate the 2013 Settlement Agreement if certain conditions are not met, if Mississippi Power is unable to secure alternate financing for any prudently-incurred Kemper IGCC costs not otherwise recovered in any Mississippi PSC rate proceeding contemplated by the 2013 Settlement Agreement, or if the Mississippi PSC fails to comply with the requirements of the 2013 Settlement Agreement. Mississippi Power continues to work with the Mississippi PSC and the Mississippi Public Utilities Staff to implement the requirements of the 2013 Settlement Agreement.

2013 MPSC Rate Order

Consistent with the terms of the 2013 Settlement Agreement, in January 2013, Mississippi Power filed a new request to increase retail rates in 2013 by $172 million annually, based on projected investment for 2013.

In March 2013, the Mississippi PSC issued the 2013 MPSC Rate Order approving retail rate increases of 15% effective March 19, 2013, and 3% effective January 1, 2014, which collectively are designed to collect $156 million annually beginning in 2014. For year-to-date 2014, $74.3 million has been collected, with $11.1 million recognized in retail revenues in Southern Company's and Mississippi Power's Condensed Statements of Income herein and the remainder deferred in other regulatory liabilities to be used to mitigate customer rate impacts after the Kemper IGCC is placed in service and included in Southern Company's and Mississippi Power's Condensed Balance Sheets herein. Since March 2013, $172.4 million has been collected, with $21.3 million recognized in retail revenues in Southern Company's and Mississippi Power's Condensed Statements of Income herein, and the remainder deferred in other regulatory liabilities to be used to mitigate customer rate impacts after the Kemper IGCC is placed in service and included in Southern Company's and Mississippi Power's Condensed Balance Sheets herein.

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 during the construction period. 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 to comply with the 2013 MPSC Rate Order by collecting and deferring the approved rates during the construction period unless directed to do otherwise by the Mississippi PSC.

In March 2013, a legal challenge to the 2013 MPSC Rate Order was filed by Thomas A. Blanton with the Mississippi Supreme Court, which remains pending against Mississippi Power and the Mississippi PSC. On April 22, 2014, the Mississippi Supreme Court requested further briefing in this proceeding on a number of substantive issues relating to the 2013 MPSC Rate Order.

Seven-Year Rate Plan

In March 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 (Seven-Year Rate Plan), which is still under review by the Mississippi PSC. In the Seven-Year Rate 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, is integral to the Seven-Year Rate 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 Seven-Year Rate 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 will review the amount and, if approved, determine the appropriate method and period of disposition.

The revenue requirements set forth in the Seven-Year Rate Plan assume the sale of a 15% undivided interest in the Kemper IGCC to SMEPA and utilization of bonus depreciation as provided by the American Taxpayer Relief Act of 2012 (ATRA), which currently requires that assets be placed in service in 2014. While Mississippi Power currently expects to place the combined cycle and the associated common facilities portion of the Kemper IGCC in service in the summer of 2014, extension of the in-service date for the remainder of the Kemper IGCC beyond 2014 results in the loss of tax benefits related to bonus depreciation under current law. The estimated value to retail customers of the bonus depreciation tax benefits not associated with the combined cycle and the associated common facilities portion of the Kemper IGCC is approximately $130 million to $160 million. See "Investment Tax Credits and Bonus Depreciation" herein for additional information regarding bonus depreciation.

Mississippi Power plans to further revise the Seven-Year Rate Plan to reflect changes including the revised in-service date, the change in expected benefits relating to tax credits, various other revenue requirement items, and other tax matters, including bonus depreciation, which include ensuring compliance with the normalization requirements of the Internal Revenue Code. The impact of these revisions for the average annual retail revenue requirement is estimated to be an increase of approximately $50 million through 2020. The revision of the Seven-Year Rate Plan is also expected to reflect rate mitigation options identified by Mississippi Power that, if approved by the Mississippi PSC, would result in no change to the total customer rate impacts contemplated in the original Seven-Year Rate Plan.

Any further cost increases and/or extensions of the in-service date with respect to the Kemper IGCC could have an adverse impact on the Seven-Year Rate Plan, including the inability to recover items considered as Cost Cap Exceptions.

In the event that the Mississippi PSC does not approve or Mississippi Power withdraws the Seven-Year Rate Plan, as ultimately revised, Mississippi Power would seek rate recovery through an alternate means, which could include a traditional rate case.

Prudence Reviews

The Mississippi PSC's review of Kemper IGCC costs is ongoing. On August 5, 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. 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.

Regulatory Assets

Consistent with the treatment of non-capital costs incurred during the pre-construction period, the Mississippi PSC granted Mississippi Power the authority to defer all non-capital Kemper IGCC-related costs to a regulatory asset during the construction period, subject to review of such costs by the Mississippi PSC. The amortization period of 40 years proposed by Mississippi Power for any such costs approved for recovery remains subject to approval 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.

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, a wholly-owned subsidiary of The North American Coal Corporation (Liberty Fuels), which will develop, construct, and manage 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 will acquire, construct, and 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.

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 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 asset purchase agreement 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 asset purchase agreement whereby Mississippi Power and SMEPA agreed to amend the power supply agreement entered into by the parties in April 2011 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 April 2011 power supply agreement were $17.5 million in 2013. In December 2013, Mississippi Power and SMEPA agreed to extend SMEPA's option to purchase through December 31, 2014. The sale and transfer of an interest in the Kemper IGCC to SMEPA are subject to approval by the Mississippi PSC.

The closing of this transaction is conditioned upon execution of a joint ownership and operating agreement, receipt of all construction permits, appropriate regulatory approvals, financing, and other conditions. In 2012, SMEPA received a conditional loan commitment from Rural Utilities Service to provide funding for SMEPA's undivided interest in the Kemper IGCC.

In 2012 and on January 2, 2014, Mississippi Power received $150 million and $75 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 asset purchase agreement or within 15 days of a request by SMEPA for a full or partial refund. Given the interest-bearing nature of the deposit and SMEPA's ability to request a refund, the deposits have been presented as a current liability in Southern Company's and Mississippi Power's Condensed Balance Sheets herein and as financing proceeds in Southern Company's and Mississippi Power's Condensed Statements of Cash Flows herein. In July 2013, Southern Company entered into an agreement with SMEPA under which Southern Company has agreed to guarantee the obligations of Mississippi Power with respect to any required refund of the deposits.

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

Baseload Act

In 2008, the Baseload Act was signed by the Governor of Mississippi. The Baseload Act authorizes, but does not require, the Mississippi PSC to adopt a cost recovery mechanism that includes in retail base rates, prior to and during construction, all or a portion of the prudently-incurred pre-construction and construction costs incurred by a utility in constructing a base load electric generating plant. Prior to the passage of the Baseload Act, such costs would traditionally be recovered only after the plant was placed in service. The Baseload Act also provides for periodic prudence reviews by the Mississippi PSC and prohibits the cancellation of any such generating plant without the approval of the Mississippi PSC. In the event of cancellation of the construction of the plant without approval of the Mississippi PSC, the Baseload Act authorizes the Mississippi PSC to make a public interest determination as to whether and to what extent the utility will be afforded rate recovery for costs incurred in connection with such cancelled generating plant. There are legal challenges to the constitutionality of the Baseload Act currently pending before the Mississippi Supreme Court. The ultimate outcome of any legal challenges to this legislation cannot be determined at this time. See "Rate Recovery of Kemper IGCC Costs" herein for additional information.

Investment Tax Credits and Bonus Depreciation

The IRS allocated $133 million (Phase I) and $279 million (Phase II) of Internal Revenue Code Section 48A tax credits to Mississippi Power in connection with the Kemper IGCC. In May 2013, the IRS notified Mississippi Power that no additional tax credits under the Internal Revenue Code Section 48A Phase III were allocated to the Kemper IGCC. As a result of the schedule extension for the Kemper IGCC, the Phase I credits have been recaptured. Through June 30, 2014, Mississippi Power had recorded tax benefits totaling $276.4 million for the remaining Phase II credits, which 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. A portion of the Phase II tax credits will be subject to recapture upon completion of SMEPA's purchase of an undivided interest in the Kemper IGCC as described above.

In January 2013, the ATRA was signed into law. The ATRA retroactively extended several tax credits through 2013 and extended 50% bonus depreciation for property placed in service in 2013 (and for certain long-term production-period projects to be placed in service in 2014), which is currently expected to apply primarily to the combined cycle and associated common facilities portion of the Kemper IGCC. The estimated cash flow benefit of approximately $120 million is dependent upon placing the assets in service in 2014. See "Rate Recovery of Kemper IGCC Costs – Seven-Year Rate Plan" herein for additional information.

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

Other Matters

Sierra Club Settlement Agreement

On August 1, 2014, Mississippi Power entered into the Sierra Club Settlement Agreement that, among other things, requires the Sierra Club to dismiss or withdraw all pending legal and regulatory challenges of the Kemper IGCC and the scrubber project at Plant Daniel Units 1 and 2. In addition, the Sierra Club agreed to refrain from initiating, intervening in, and/or challenging certain legal and regulatory proceedings for the Kemper IGCC, including, but not limited to, the prudence review, and Plant Daniel for a period of three years from the date of the Sierra Club Settlement Agreement. On August 4, 2014, the Sierra Club filed all of the required motions necessary to dismiss or withdraw.

Under the Sierra Club Settlement Agreement, Mississippi Power agreed to, among other things, fund a $15 million grant payable over a five-year period for an energy efficiency and renewable program and contribute $2 million to a conservation fund. In addition, and consistent with Mississippi Power's ongoing evaluation of recent environmental rules and regulations, Mississippi Power agreed to retire, repower with natural gas, or convert to an alternative non-fossil fuel source Plant Sweatt Units 1 and 2 (80 MWs) no later than December 2018. Mississippi Power also agreed that it would cease burning coal and other solid fuel at Plant Watson Units 4 and 5 (750 MWs) and begin operating those units solely on natural gas no later than April 2015, and cease burning coal and other solid fuel at Plant Greene County Units 1 and 2 (200 MWs) and begin operating those units solely on natural gas no later than April 2016. See "Retail Regulatory Matters – Mississippi Power – Environmental Compliance Overview Plan" herein for additional information.

XML

Contingencies and Regulatory Matters Retail Regulatory Matters (Details) (Alabama Power [Member], USD $)	Jun. 30, 2014	Dec. 31, 2013
Loss Contingencies [Line Items]
Under recovered rate CNP environmental balance	$ 32,000,000	$ 7,000,000
Under Recovered Rate Cnp Balance	33,000,000	18,000,000
Other Regulatory Liabilities, Current	33,000,000	37,000,000
Deferred Over Recovered Regulatory Clause Revenues	0	15,000,000
Accumulated reserve balance for future storms	87,000,000	96,000,000
Fuel Recovery Clause [Member]
Loss Contingencies [Line Items]
Other Regulatory Liabilities, Current	19,000,000	27,000,000
Deferred Over Recovered Regulatory Clause Revenues	$ 0	$ 15,000,000

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Financing Debt Instruments (Details) (USD $)	6 Months Ended					6 Months Ended					0 Months Ended	6 Months Ended						6 Months Ended	1 Months Ended						1 Months Ended		6 Months Ended			1 Months Ended					6 Months Ended							6 Months Ended					6 Months Ended
	Jun. 30, 2014	Jun. 30, 2014 Debt Redemptions [Member]		Jun. 30, 2014 Debt Issuances [Member]	Jun. 30, 2014 Traditional Operating Companies [Member]	Jun. 30, 2014 Southern Company [Member]	Jun. 30, 2013 Southern Company [Member]	Jun. 30, 2014 Southern Company [Member] Debt Redemptions [Member]		Jun. 30, 2014 Southern Company [Member] Debt Issuances [Member]	Feb. 20, 2014 Georgia Power [Member]	Jun. 30, 2014 Georgia Power [Member]	Feb. 20, 2014 Georgia Power [Member] Line of Credit [Member] Debt Due Two Thousand Forty Four [Member]	Feb. 20, 2014 Georgia Power [Member] Line of Credit [Member] Debt Due Two Thousand Twenty Nine [Member]	Jun. 30, 2014 Georgia Power [Member] Debt Redemptions [Member]		Jun. 30, 2014 Georgia Power [Member] Debt Issuances [Member]	Jun. 30, 2014 Gulf Power [Member]	Jun. 30, 2014 Gulf Power [Member] Series 2012 [Member]	Jun. 30, 2014 Gulf Power [Member] Debt Redemptions [Member]		Apr. 01, 2014 Gulf Power [Member] Debt Redemptions [Member]	Jun. 30, 2014 Gulf Power [Member] Debt Issuances [Member]	Apr. 01, 2014 Gulf Power [Member] Debt Issuances [Member]	May 31, 2014 Mississippi Power [Member]	Jan. 31, 2014 Mississippi Power [Member]	Jun. 30, 2014 Mississippi Power [Member]		Jun. 30, 2013 Mississippi Power [Member]	May 31, 2014 Mississippi Power [Member] Series 2013A [Member]	Jun. 30, 2014 Mississippi Power [Member] Debt Redemptions [Member]		Jun. 30, 2014 Mississippi Power [Member] Debt Issuances [Member]		Jun. 30, 2014 Southern Power [Member]	Jun. 30, 2014 Southern Power [Member] Debt Due April Thirtieth Two Thousand Thirty Three [Member]	Jun. 30, 2014 Southern Power [Member] Debt Due April Thirtieth Two Thousand Thirty Four [Member]	Jun. 30, 2014 Southern Power [Member] Debt Due May Thirty First Two Thousand Thirty Four [Member]	Jun. 30, 2014 Southern Power [Member] Debt Redemptions [Member]		Jun. 30, 2014 Southern Power [Member] Debt Issuances [Member]	Jun. 30, 2014 Other Subsidiaries [Member]	Jun. 30, 2014 Other Subsidiaries [Member] Debt Redemptions [Member]		Jun. 30, 2014 Other Subsidiaries [Member] Debt Issuances [Member]	Jun. 30, 2014 Plant Vogtle Units 3 And 4 [Member] Georgia Power [Member]	Jun. 30, 2014 Consolidation, Eliminations [Member]		Jun. 30, 2014 Consolidation, Eliminations [Member] Debt Redemptions [Member]		Jun. 30, 2014 Consolidation, Eliminations [Member] Debt Issuances [Member]
Debt Instrument [Line Items]
Remarketing Revenue Bond																		$ 13,000,000
Maturities of Senior Debt	350,000,000					350,000,000						0						0									0	[1]							0							0					0	[2]
Revenue Bond Issuances	42,000,000					0						0						42,000,000	13,000,000								0	[1]							0							0					0	[2]
Revenue Bond Redemptions	66,000,000					0						37,000,000						29,000,000									0	[1]							0							0					0	[2]
Line of Credit Facility, Current Borrowing Capacity											1,000,000,000
Jointly Owned Utility Plant, Proportionate Ownership Share																																														45.70%
Amount of Variable Rate Pollution Control Revenue Bonds Outstanding Requiring Liquidity Support	1,700,000,000				495,000,000
Debt Instrument, Face Amount													500,000,000	500,000,000
Other Long-term Debt		15,000,000	[3]	1,272,000,000				0	[3]	0					3,000,000	[3]	1,000,000,000			0	[3]		0								1,000,000	[1],[3]	482,000,000	[1]					1,000,000	[3]	10,000,000		10,000,000	[3]	0				0	[2],[3]	(220,000,000)	[2]
Debt Instrument, Interest Rate, Stated Percentage													3.86%	3.488%
Payments of Debt Issuance Costs											66,000,000
Long-term Pollution Control Bond																						29,075,000.000		29,075,000.000
Bank Loans Period Of Extension																									19 months	18 months
Aggregate Principal Amount Of Floating Rate Bank Loan																									220,000,000	250,000,000
Taxable Revenue Bond																														12,300,000
Debt Instrument, Description of Variable Rate Basis																											P1M
Promissory Note																																				800,000	3,800,000	5,300,000
Interest Bearing Refundable Deposit Related to Asset Sale						75,000,000	0																			75,000,000	75,000,000		0
Repayments of Long-term Debt																																			$ 800,000

[1] Includes reductions in capital lease obligations resulting from cash payments under capital leases.

[2] Intercompany loan from Southern Company to Mississippi Power eliminated in Southern Company's Condensed Consolidated Financial Statements.

[3] Includes remarketing by Gulf Power of $13 million aggregate principal amount of revenue bonds previously purchased and held by Gulf Power since December 2013.

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Contingencies and Regulatory Matters (Tables)

6 Months Ended

Jun. 30, 2014

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	June 30, 2014		December 31, 2013
		(in millions)
Rate CNP Environmental – Under	Deferred under recovered regulatory clause revenues	$	32	$	7
Rate CNP PPA – Under	Deferred under recovered regulatory clause revenues	33		18
Retail Energy Cost Recovery – Over	Other regulatory liabilities, current	19		27
	Deferred over recovered regulatory clause revenues	—		15
Natural Disaster Reserve	Other regulatory liabilities, deferred	87		96

Recovery Position of Each Regulatory Clause

The recovery balance of each regulatory clause follows:

Recovery Clause	Balance Sheet Location	June 30, 2014		December 31, 2013
		(in millions)
Fuel Cost Recovery – Under	Under recovered regulatory clause revenues	$	43.4	$	21.0
Purchased Power Capacity Recovery – Over	Other regulatory liabilities, current	9.1		—
Purchased Power Capacity Recovery – Under	Under recovered regulatory clause revenues	—		2.8
Environmental Cost Recovery – Under	Under recovered regulatory clause revenues	15.1		14.4
Energy Conservation Cost Recovery – Under	Under recovered regulatory clause revenues	4.9		7.0

Current And Actual Cost Estimate for Kemper IGCC

Mississippi Power's 2010 project estimate, current cost estimate, and actual costs incurred as of June 30, 2014 for the Kemper IGCC are as follows:

Cost Category	2010 Project Estimate(e)		Current Estimate		Actual Costs at June 30, 2014
	(in billions)
Plant Subject to Cost Cap(a)	$	2.40	$	4.44	$	3.81
Lignite Mine and Equipment	0.21		0.24		0.23
CO2 Pipeline Facilities	0.14		0.11		0.10
AFUDC(b)(c)	0.17		0.55		0.37
General Exceptions	0.05		0.10		0.07
Regulatory Asset(c)(d)	—		0.12		0.09
Total Kemper IGCC(a)(c)	$	2.97	$	5.56	$	4.67

(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.

(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."

(c) Amounts in the Current Estimate reflect costs through May 31, 2015, but do not reflect any adjustments as a result of the expected placement of the combined cycle and the associated common facilities portion of the Kemper IGCC in service in the summer of 2014.

(d) 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."

(e) 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.