10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

þQUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 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 March 31, 2014
The Southern Company	Par Value $5 Per Share	890,811,428
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

March 31, 2014

		Page     Number
DEFINITIONS		5
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION		7
	PART I—FINANCIAL INFORMATION
Item 1.	Financial Statements (Unaudited)
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations
	The Southern Company and Subsidiary Companies
	Condensed Consolidated Statements of Income	10
	Condensed Consolidated Statements of Comprehensive Income	11
	Condensed Consolidated Statements of Cash Flows	12
	Condensed Consolidated Balance Sheets	13
	Management's Discussion and Analysis of Financial Condition and Results of Operations	15
	Alabama Power Company
	Condensed Statements of Income	33
	Condensed Statements of Comprehensive Income	33
	Condensed Statements of Cash Flows	34
	Condensed Balance Sheets	35
	Management's Discussion and Analysis of Financial Condition and Results of Operations	37
	Georgia Power Company
	Condensed Statements of Income	48
	Condensed Statements of Comprehensive Income	48
	Condensed Statements of Cash Flows	49
	Condensed Balance Sheets	50
	Management's Discussion and Analysis of Financial Condition and Results of Operations	52
	Gulf Power Company
	Condensed Statements of Income	66
	Condensed Statements of Comprehensive Income	66
	Condensed Statements of Cash Flows	67
	Condensed Balance Sheets	68
	Management's Discussion and Analysis of Financial Condition and Results of Operations	70
	Mississippi Power Company
	Condensed Statements of Operations	82
	Condensed Statements of Comprehensive Income (Loss)	82
	Condensed Statements of Cash Flows	83
	Condensed Balance Sheets	84
	Management's Discussion and Analysis of Financial Condition and Results of Operations	86
	Southern Power Company and Subsidiary Companies
	Condensed Consolidated Statements of Income	105
	Condensed Consolidated Statements of Comprehensive Income	105
	Condensed Consolidated Statements of Cash Flows	106
	Condensed Consolidated Balance Sheets	107
	Management's Discussion and Analysis of Financial Condition and Results of Operations	109
	Notes to the Condensed Financial Statements	116
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	31
Item 4.	Controls and Procedures	31

3

INDEX TO QUARTERLY REPORT ON FORM 10-Q

March 31, 2014

		Page     Number
	PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	150
Item 1A.	Risk Factors	150
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	150
	Signatures	153

4

DEFINITIONS

Term	Meaning
2012 MPSC CPCN Order	A detailed order issued by the Mississippi PSC in April 2012 confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing the acquisition, construction, and operation of the Kemper IGCC
2013 ARP	Alternative Rate Plan approved by the Georgia PSC for Georgia Power for the years 2014 through 2016
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
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
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
MATS rule	Mercury and Air Toxics Standards rule
Mississippi Power	Mississippi Power Company
mmBtu	Million British thermal unit
Moody's	Moody's Investors Service, Inc.
MW	Megawatt
MWH	Megawatt-hour
NCCR	Nuclear Construction Cost Recovery
NDR	Natural Disaster Reserve
NRC	U.S. Nuclear Regulatory Commission
OCI	Other comprehensive income

5

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
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	Rate Certificated New Plant
Rate CNP Environmental	Rate Certificated New Plant Environmental
Rate CNP PPA	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

6

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

This Quarterly Report on Form 10-Q contains forward-looking statements. Forward-looking statements include, among other things, statements concerning retail sales, retail rates, the strategic goals for the wholesale business, customer growth, economic recovery, fuel and environmental cost recovery and other rate actions, current and proposed environmental regulations and related 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 or non-performance under construction or other agreements, operational performance, delays associated with start-up activities, including major equipment failure, system integration, and operations, and/or unforeseen engineering problems;

• 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;

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

• actions related to cost recovery for the Kemper IGCC, including actions relating to proposed securitization, Mississippi PSC approval of Mississippi Power's proposed rate recovery plan, as ultimately amended, which 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;

7

• 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, or the Baseload Act;

• 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.

8

THE SOUTHERN COMPANY

AND SUBSIDIARY COMPANIES

9

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended March 31,
	2014			2013
	(in millions)
Operating Revenues:
Retail revenues	$	3,858		$	3,298
Wholesale revenues	604			432
Other electric revenues	165			155
Other revenues	17			12
Total operating revenues	4,644			3,897
Operating Expenses:
Fuel	1,647			1,262
Purchased power	187			95
Other operations and maintenance	986			974
Depreciation and amortization	497			466
Taxes other than income taxes	247			235
Estimated loss on Kemper IGCC	380			540
Total operating expenses	3,944			3,572
Operating Income	700			325
Other Income and (Expense):
Allowance for equity funds used during construction	57			41
Interest expense, net of amounts capitalized	(206		)	(211		)
Other income (expense), net	(7		)	(27		)
Total other income and (expense)	(156		)	(197		)
Earnings Before Income Taxes	544			128
Income taxes	176			31
Consolidated Net Income	368			97
Dividends on Preferred and Preference Stock of Subsidiaries	17			16
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries	$	351		$	81
Common Stock Data:
Earnings per share (EPS) -
Basic EPS	$	0.39		$	0.09
Diluted EPS	$	0.39		$	0.09
Average number of shares of common stock outstanding (in millions)
Basic	890			870
Diluted	893			875
Cash dividends paid per share of common stock	$	0.5075		$	0.4900

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 COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended March 31,
	2014			2013
	(in millions)
Consolidated Net Income	$	368		$	97
Other comprehensive income (loss):
Qualifying hedges:
Reclassification adjustment for amounts included in net income, net of tax of $1 and $2, respectively	1			3
Pension and other post retirement benefit plans:
Reclassification adjustment for amounts included in net income, net of tax of $- and $1, respectively	1			1
Total other comprehensive income (loss)	2			4
Dividends on preferred and preference stock of subsidiaries	(17		)	(16		)
Comprehensive Income	$	353		$	85

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 STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Three Months Ended March 31,
	2014			2013
	(in millions)
Operating Activities:
Consolidated net income	$	368		$	97
Adjustments to reconcile consolidated net income to net cash provided from operating activities —
Depreciation and amortization, total	587			568
Deferred income taxes	(37		)	(92		)
Allowance for equity funds used during construction	(57		)	(41		)
Stock based compensation expense	28			26
Estimated loss on Kemper IGCC	380			540
Other, net	(8		)	(19		)
Changes in certain current assets and liabilities —
-Receivables	(128		)	29
-Fossil fuel stock	441			36
-Materials and supplies	(5		)	52
-Other current assets	(114		)	(72		)
-Accounts payable	(109		)	(47		)
-Accrued taxes	(44		)	(98		)
-Accrued compensation	(144		)	(282		)
-Other current liabilities	(55		)	40
Net cash provided from operating activities	1,103			737
Investing Activities:
Property additions	(1,180		)	(1,197		)
Investment in restricted cash	—			(78		)
Distribution of restricted cash	9			1
Nuclear decommissioning trust fund purchases	(231		)	(262		)
Nuclear decommissioning trust fund sales	229			261
Cost of removal, net of salvage	(22		)	(30		)
Change in construction payables, net	51			6
Prepaid long-term service agreement	(64		)	(31		)
Other investing activities	(7		)	51
Net cash used for investing activities	(1,215		)	(1,279		)
Financing Activities:
Increase (decrease) in notes payable, net	(884		)	468
Proceeds —
Long-term debt issuances	1,251			1,035
Interest-bearing refundable deposit related to asset sale	75			—
Common stock issuances	128			42
Redemptions —
Long-term debt	(9		)	(656		)
Common stock repurchased	(4		)	(18		)
Payment of common stock dividends	(451		)	(426		)
Payment of dividends on preferred and preference stock of subsidiaries	(17		)	(16		)
Other financing activities	(46		)	—
Net cash provided from financing activities	43			429
Net Change in Cash and Cash Equivalents	(69		)	(113		)
Cash and Cash Equivalents at Beginning of Period	659			628
Cash and Cash Equivalents at End of Period	$	590		$	515
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $22 and $17 capitalized for 2014 and 2013, respectively)	$	186		$	187
Income taxes, net	(7		)	4
Noncash transactions — accrued property additions at end of period	450			501

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)

Assets	At March 31, 2014			At December 31, 2013
	(in millions)
Current Assets:
Cash and cash equivalents	$	590		$	659
Receivables —
Customer accounts receivable	1,063			1,027
Unbilled revenues	382			448
Under recovered regulatory clause revenues	72			58
Other accounts and notes receivable	306			304
Accumulated provision for uncollectible accounts	(17		)	(18		)
Fossil fuel stock, at average cost	898			1,339
Materials and supplies, at average cost	963			959
Vacation pay	171			171
Prepaid expenses	525			489
Other regulatory assets, current	117			124
Other current assets	70			39
Total current assets	5,140			5,599
Property, Plant, and Equipment:
In service	66,369			66,021
Less accumulated depreciation	23,329			23,059
Plant in service, net of depreciation	43,040			42,962
Other utility plant, net	234			240
Nuclear fuel, at amortized cost	874			855
Construction work in progress	7,425			7,151
Total property, plant, and equipment	51,573			51,208
Other Property and Investments:
Nuclear decommissioning trusts, at fair value	1,513			1,465
Leveraged leases	670			665
Miscellaneous property and investments	224			218
Total other property and investments	2,407			2,348
Deferred Charges and Other Assets:
Deferred charges related to income taxes	1,448			1,432
Prepaid pension costs	423			419
Unamortized debt issuance expense	202			139
Unamortized loss on reacquired debt	286			293
Other regulatory assets, deferred	2,654			2,557
Other deferred charges and assets	705			551
Total deferred charges and other assets	5,718			5,391
Total Assets	$	64,838		$	64,546

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

13

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholders' Equity	At March 31, 2014			At December 31, 2013
	(in millions)
Current Liabilities:
Securities due within one year	$	768		$	469
Interest-bearing refundable deposit related to asset sale	225			150
Notes payable	598			1,482
Accounts payable	1,386			1,376
Customer deposits	384			380
Accrued taxes —
Accrued income taxes	114			13
Other accrued taxes	243			456
Accrued interest	253			251
Accrued vacation pay	213			217
Accrued compensation	177			303
Other regulatory liabilities, current	116			92
Other current liabilities	358			347
Total current liabilities	4,835			5,536
Long-term Debt	22,288			21,344
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	10,558			10,563
Deferred credits related to income taxes	197			202
Accumulated deferred investment tax credits	962			966
Employee benefit obligations	1,446			1,461
Asset retirement obligations	2,004			2,006
Other cost of removal obligations	1,298			1,270
Other regulatory liabilities, deferred	481			475
Other deferred credits and liabilities	568			584
Total deferred credits and other liabilities	17,514			17,527
Total Liabilities	44,637			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 — March 31, 2014: 894 million shares
— December 31, 2013: 893 million shares
Treasury — March 31, 2014: 3.3 million shares
— December 31, 2013: 5.7 million shares
Par value	4,467			4,461
Paid-in capital	5,405			5,362
Treasury, at cost	(139		)	(250		)
Retained earnings	9,410			9,510
Accumulated other comprehensive loss	(73		)	(75		)
Total Common Stockholders' Equity	19,070			19,008
Preferred and Preference Stock of Subsidiaries	756			756
Total Stockholders' Equity	19,826			19,764
Total Liabilities and Stockholders' Equity	$	64,838		$	64,546

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

14

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

FIRST QUARTER 2014 vs. FIRST QUARTER 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 the first quarter 2014, as compared to the target.

RESULTS OF OPERATIONS

Net Income

First Quarter 2014 vs. First Quarter 2013
(change in millions)	(% change)
$270	N/M

N/M – Not meaningful

Southern Company's first quarter 2014 net income after dividends on preferred and preference stock of subsidiaries was $351 million ($0.39 per share) compared to $81 million ($0.09 per share) for the first quarter 2013. The increase was primarily related to an increase in revenues due to colder weather in the first quarter 2014 compared to the corresponding period in 2013 as well as retail base rate increases. In addition, in the first quarter 2014, Southern Company recorded a $380 million pre-tax charge ($235 million after tax) compared to a $540 million pre-tax charge ($333 million after tax) in the first quarter 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 $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

15

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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).

Retail Revenues

First Quarter 2014 vs. First Quarter 2013
(change in millions)	(% change)
$560	17.0

In the first quarter 2014, retail revenues were $3.9 billion compared to $3.3 billion for the corresponding period in 2013.

Details of the changes in retail revenues were as follows:

	First Quarter 2014
	(in millions)		(% change)
Retail – prior year	$	3,298
Estimated change resulting from –
Rates and pricing	84		2.5
Sales growth	14		0.4
Weather	117		3.6
Fuel and other cost recovery	345		10.5
Retail – current year	$	3,858	17.0%

Revenues associated with changes in rates and pricing increased in the first quarter 2014 when compared to the corresponding period in 2013 primarily due retail rate increases at all of the traditional operating companies. The increase 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 collecting 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 a 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. 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 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 first quarter 2014 when compared to the corresponding period in 2013. The increase was due to a 2.8% increase in industrial KWH sales and a 1.2% increase in weather-adjusted residential KWH sales, partially offset by a 0.2% decrease in weather-adjusted commercial KWH sales. The increase in industrial KWH sales for the first quarter 2014 was primarily due to increases in the primary metals, transportation, stone, clay, and glass, and lumber sectors. The increase in weather-adjusted residential KWH sales for the first quarter 2014 was primarily due to customer growth and increased customer usage. The decrease in weather-adjusted commercial KWH sales for the first quarter 2014 was primarily due to decreased customer usage, partially offset by customer growth.

Fuel and other cost recovery revenues increased $345 million in the first quarter 2014 when compared to the corresponding period in 2013 primarily due to higher fuel costs and increased energy sales.

16

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

First Quarter 2014 vs. First Quarter 2013
(change in millions)	(% change)
$172	39.8

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 first quarter 2014, wholesale revenues were $604 million compared to $432 million for the corresponding period in 2013, reflecting a $174 million increase in energy revenues, partially offset by a $2 million decrease in capacity 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 and requirements contracts.

Other Electric Revenues

First Quarter 2014 vs. First Quarter 2013
(change in millions)	(% change)
$10	6.5

In the first quarter 2014, other electric revenues were $165 million compared to $155 million for the corresponding period in 2013. The increase was primarily due to an increase in transmission revenues related to the open access transmission tariff.

Fuel and Purchased Power Expenses

	First Quarter 2014 vs. First Quarter 2013
	(change in millions)		(% change)
Fuel	$	385	30.5
Purchased power	92		96.8
Total fuel and purchased power expenses	$	477

In the first quarter 2014, total fuel and purchased power expenses were $1.83 billion compared to $1.36 billion for the corresponding period in 2013. The increase was primarily the result of a $283 million increase in the average cost of fuel and purchased power primarily due to higher natural gas prices and a $209 million increase in the volume of KWHs generated primarily due to increased demand resulting from colder weather in the first quarter

17

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

2014 compared to the corresponding period in 2013, partially offset by a $15 million decrease in the volume of KWHs purchased as the marginal cost of 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.

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

	First Quarter 2014	First Quarter 2013
Total generation (billions of KWHs)	47	43
Total purchased power (billions of KWHs)	3	3
Sources of generation (percent) —
Coal	47	34
Nuclear	16	17
Gas	33	44
Hydro	4	5
Cost of fuel, generated (cents per net KWH) —
Coal	4.19	4.14
Nuclear	0.89	0.85
Gas	4.19	3.11
Average cost of fuel, generated (cents per net KWH)	3.63	3.08
Average cost of purchased power (cents per net KWH)(a)	8.89	4.64

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

Fuel

In the first quarter 2014, fuel expense was $1.65 billion compared to $1.26 billion for the corresponding period in 2013. The increase was primarily due to a 34.7% increase in the average cost of natural gas per KWH generated and a 52.8% increase in the volume of KWHs generated by coal, partially offset by a 19.9% decrease in the volume of KWHs generated by natural gas.

Purchased Power

In the first quarter 2014, purchased power expense was $187 million compared to $95 million for the corresponding period in 2013. The increase was primarily due to a 91.6% increase in the average cost per KWH purchased, partially offset by a 10.8% decrease in the volume of KWHs purchased as the marginal cost of generation available was lower than the market cost of available energy.

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.

18

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Other Operations and Maintenance Expenses

First Quarter 2014 vs. First Quarter 2013
(change in millions)	(% change)
$12	1.2

In the first quarter 2014, other operations and maintenance expenses were $986 million compared to $974 million for the corresponding period in 2013. The increase was primarily due to a $27 million increase in scheduled outage and maintenance costs, a $17 million increase in commodity and labor costs, and a $7 million increase in transmission and distribution costs, partially offset by a $25 million deferral of certain non-nuclear outage expenditures under an accounting order at Alabama Power and a $14 million decrease in pension costs. See Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Alabama Power – Non-Nuclear Outage Accounting Order" in Item 8 of the Form 10-K for additional information related to non-nuclear outage expenditures. Also see Note (F) to the Condensed Financial Statements herein for additional information related to pension costs.

Depreciation and Amortization

First Quarter 2014 vs. First Quarter 2013
(change in millions)	(% change)
$31	6.7

In the first quarter 2014, depreciation and amortization was $497 million compared to $466 million for the corresponding period in 2013. The increase was 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 2013 as well as 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, and reductions in depreciation at Gulf Power, as approved by the Florida PSC.

Taxes Other Than Income Taxes

First Quarter 2014 vs. First Quarter 2013
(change in millions)	(% change)
$12	5.1

In the first quarter 2014, taxes other than income taxes were $247 million compared to $235 million for the corresponding period in 2013. The increase was primarily the result of an increase in municipal franchise fees related to higher retail revenues in 2014.

Estimated Loss on Kemper IGCC

First Quarter 2014 vs. First Quarter 2013
(change in millions)	(% change)
$(160)	(29.6)

In the first quarters of 2014 and 2013, estimated probable losses on the Kemper IGCC of $380 millionand$540 million, respectively, were recorded at Southern Company to 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 the DOE Grants and excluding the 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.

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Allowance for Equity Funds Used During Construction

First Quarter 2014 vs. First Quarter 2013
(change in millions)	(% change)
$16	39.0

In the first quarter 2014, AFUDC equity was $57 million compared to $41 million for the corresponding period in 2013. The increase was 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.

Other Income (Expense), Net

First Quarter 2014 vs. First Quarter 2013
(change in millions)	(% change)
$20	74.1

In the first quarter 2014, other income (expense), net was $(7) million compared to $(27) 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.

Income Taxes

First Quarter 2014 vs. First Quarter 2013
(change in millions)	(% change)
$145	N/M

N/M – Not meaningful

In the first quarter 2014, income taxes were $176 million compared to $31 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 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 supply business. Future earnings for the electricity business in the near term will depend, in part, upon maintaining energy 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 supply 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

20

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

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). 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. Pending such further proceedings, it is anticipated that CSAPR will remain stayed and the EPA will continue to administer the Clean Air Interstate Rule. The ultimate outcome of this matter 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 Company in Item 7 of the Form 10-K for additional information regarding the EPA's proposed rule for cooling water intake structures.

On April 16, 2014, the EPA requested an extension of its deadline for issuing a final rule for cooling water intake structures until May 16, 2014.

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.

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 March 31, 2014, Georgia Power, Gulf Power, and Mississippi Power had total under recovered fuel costs included on Southern Company's Condensed Balance Sheet

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

herein of approximately $195 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 Sheets herein was approximately $22 million at March 31, 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

Storm Damage Recovery

Georgia Power defers and recovers certain costs related to damages from major storms as mandated by the Georgia PSC. As of March 31, 2014 and December 31, 2013, the balance in the regulatory asset related to storm damage was $110 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 $170 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," 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 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.

22

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Through March 31, 2014, Southern Company incurred pre-tax charges of $1.6 billion ($963 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 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)totheCondensedFinancialStatementshereinorinNote3tothefinancialstatementsofSouthernCompanyinItem8oftheForm10-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 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. Currently, Alabama Power and Georgia Power are paying the fee of approximately $13 million and $15 million annually, respectively, based on their ownership interest. 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

23

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

Mississippi Power has extended the scheduled in-service date for the Kemper IGCC to the first half of 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 revised 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, in addition to charges totaling $1.18 billion ($728.7 million after tax) recognized through December 31, 2013. 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 and/or any amount in excess of the $1.0 billion securitization limit 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, and/or start-up activities for this "first-of-a-kind" technology, including major equipment failure, system integration, and operations, and/or unforeseen engineering problems.

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.

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 three months ended March 31, 2014 were negatively affected by revisions to the cost estimate for the Kemper IGCC, Southern Company's financial condition remained stable at March 31, 2014. Through March 31, 2014, Southern Company has incurred non-recoverable cash expenditures of $636 million and is expected to incur approximately $924 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 $1.1 billion for the first three months of 2014, an increase of $366 million from the corresponding period in 2013. The increase in net cash provided from operating activities was primarily due to a reduction in fossil fuel stock resulting from an increase in KWH generation. Net cash used for investing activities totaled $1.2 billion for the first three months of 2014 primarily due to property additions to utility plant. Net cash used for financing activities totaled $43 million for the first three months of 2014. This was primarily due to a decrease in notes payable, net and payments of common stock dividends, partially offset by issuances of long-term debt. Fluctuations in cash flow from financing activities vary from year to year based on capital needs and the maturity or redemption of securities.

24

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Significant balance sheet changes for the first three months of 2014 include an increase of $365 million in total property, plant, and equipment for construction of generation, transmission, and distribution facilities. Other significant changes include a $944 million increase in long-term debt (excluding amounts due within a year) to repay maturing debt and to fund the Southern Company subsidiaries' continuous construction programs and an increase of $299 million in securities due within one year, partially offset by a decrease of $884 million in notes payable due to bank note redemptions and reductions in commercial paper.

At the end of the first quarter 2014, the market price of Southern Company's common stock was $43.94 per share (based on the closing price as reported on the New York Stock Exchange) and the book value was $21.41 per share, representing a market-to-book ratio of 205%, compared to $41.11, $21.43, and 192%, respectively, at the end of 2013. The dividend for the first quarter 2014 was $0.5075 per share compared to $0.49 per share in the first quarter 2013. In April 2014, the quarterly dividend payable in June 2014 was increased to $0.5250 per share.

Capital Requirements and Contractual Obligations

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Southern Company in Item 7 of the Form 10-K for a description of Southern Company's capital requirements for the construction programs of the Southern Company system, including estimated capital expenditures for new generating facilities and to comply with existing environmental statutes and regulations, and other funding requirements associated with scheduled maturities of long-term debt, as well as related interest, preferred and preference stock dividends, leases, trust funding requirements, other purchase commitments, unrecognized tax benefits and interest, and derivative obligations. Approximately $797 million will be required through March 31, 2015 to fund maturities and announced redemptions 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 years relating to its proposed ownership interest). These 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 the expected environmental compliance program; 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 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 "PSC Matters – Georgia Power – Nuclear Construction" and "Integrated Coal Gasification Combined Cycle" herein for additional information.

Sources of Capital

Southern Company intends to meet its future capital needs through internal cash flow and external security issuances. Equity capital can be provided from any combination of Southern Company's stock plans, private

25

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 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 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% 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. 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.

In 2011, Mississippi Power 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. See Note 3 to the financial statements of Southern Company and Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and 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.

26

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

At March 31, 2014, Southern Company and its subsidiaries had approximately $590 million of cash and cash equivalents. Committed credit arrangements with banks at March 31, 2014 were as follows:

	Expires(a)												Executable Term Loans				Due Within One Year
Company	2014		2015		2016		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	238		35		—		1,030		1,303		1,303		53		—		53		185
Georgia Power	—		—		150		1,600		1,750		1,736		—		—		—		—
Gulf Power	75		35		165		—		275		275		50		—		50		60
Mississippi Power	135		—		165		—		300		300		25		40		65		70
Southern Power	—		—		—		500		500		500		—		—		—		—
Other	75		25		—		—		100		100		25		—		25		50
Total	$	523	$	95	$	480	$	4,130	$	5,228	$	5,214	$	153	$	40	$	193	$	365

(a) No credit arrangements expire in 2017.

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

A portion of the unused credit with banks is allocated to provide liquidity support to the traditional operating companies' variable rate pollution control revenue bonds and commercial paper programs. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of March 31, 2014 was approximately $1.8 billion. In addition, at March 31, 2014, the traditional operating companies had $559 million of fixed rate pollution control revenue bonds that were required to be remarketed within the next 12 months. Subsequent to March 31, 2014, $234 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 credit arrangements as needed, prior to expiration.

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 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.

27

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Details of short-term borrowings were as follows:

	Short-term Debt at March 31, 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	$	598	0.2%	$	776	0.2%	$	1,104
Short-term bank debt	—		—%	227		0.9%	400
Total	$	598	0.2%	$	1,003	0.3%

(a)    Average and maximum amounts are based upon daily balances during the three-month period ended March 31, 2014.

Management believes that the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, 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, emissions allowances, energy price risk management, and construction of new generation.

The maximum potential collateral requirements under these contracts at March 31, 2014 were as follows:

Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB and Baa2	$	9
At BBB- and/or Baa3	473
Below BBB- and/or Baa3	2,381

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 quarter 2014, Southern Company issued approximately 1.3 million shares of common stock for approximately $35.3 million through the employee and director stock plans, of which 150,000 shares related to Southern Company's performance share plan.

In August 2013, Southern Company began using shares held in treasury to satisfy the requirements under the Southern Investment Plan and the employee savings plan and, during the first quarter 2014, issued approximately 2.4 million shares for approximately $101.0 million.

28

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

Company(a)	Other Long-Term Debt Issuances		Other Long-Term Debt Redemptions(b)
	(in millions)
Georgia Power	$	1,000	$	1
Mississippi Power	250		1
Southern Power	1		1
Other	—		6
Total	$	1,251	$	9

(a) Southern Company, Alabama Power, and Gulf Power did not issue or redeem any long-term debt during the first three months of 2014.

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

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.

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 will 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 March 31, 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 will be used for the announced redemption, on May 15, 2014, of $29.075 million aggregate principal amount of MBFC Pollution Control Revenue Refunding Bonds, Series 2003 (Gulf Power Company Project).

29

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

30

PART I

Item 3. Quantitative And Qualitative Disclosures About Market Risk.

During the three months ended March 31, 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 first 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.

31

ALABAMA POWER COMPANY

32

ALABAMA POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended March 31,
	2014			2013
	(in millions)
Operating Revenues:
Retail revenues	$	1,297		$	1,141
Wholesale revenues, non-affiliates	85			59
Wholesale revenues, affiliates	69			56
Other revenues	57			52
Total operating revenues	1,508			1,308
Operating Expenses:
Fuel	432			372
Purchased power, non-affiliates	57			20
Purchased power, affiliates	49			31
Other operations and maintenance	325			330
Depreciation and amortization	175			158
Taxes other than income taxes	89			90
Total operating expenses	1,127			1,001
Operating Income	381			307
Other Income and (Expense):
Allowance for equity funds used during construction	10			8
Interest expense, net of amounts capitalized	(62		)	(66		)
Other income (expense), net	(5		)	(1		)
Total other income and (expense)	(57		)	(59		)
Earnings Before Income Taxes	324			248
Income taxes	127			97
Net Income	197			151
Dividends on Preferred and Preference Stock	10			10
Net Income After Dividends on Preferred and Preference Stock	$	187		$	141

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended March 31,
	2014		2013
	(in millions)
Net Income	$	197	$	151
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $- and $-, respectively	—		—
Total other comprehensive income (loss)	—		—
Comprehensive Income	$	197	$	151

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

33

ALABAMA POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Three Months Ended March 31,
	2014			2013
	(in millions)
Operating Activities:
Net income	$	197		$	151
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	210			206
Deferred income taxes	25			25
Allowance for equity funds used during construction	(10		)	(8		)
Other, net	(22		)	9
Changes in certain current assets and liabilities —
-Receivables	(17		)	(13		)
-Fossil fuel stock	99			28
-Materials and supplies	3			16
-Other current assets	(81		)	(71		)
-Accounts payable	(139		)	(124		)
-Accrued taxes	147			90
-Accrued compensation	(37		)	(61		)
-Retail fuel cost over recovery	(20		)	21
-Other current liabilities	(3		)	1
Net cash provided from operating activities	352			270
Investing Activities:
Property additions	(287		)	(274		)
Nuclear decommissioning trust fund purchases	(56		)	(57		)
Nuclear decommissioning trust fund sales	56			57
Cost of removal, net of salvage	(12		)	(9		)
Change in construction payables	49			(1		)
Other investing activities	(5		)	37
Net cash used for investing activities	(255		)	(247		)
Financing Activities:
Increase in notes payable, net	—			45
Capital contributions from parent company	7			5
Payment of preferred and preference stock dividends	(10		)	(10		)
Payment of common stock dividends	(137		)	(132		)
Other financing activities	—			(3		)
Net cash used for financing activities	(140		)	(95		)
Net Change in Cash and Cash Equivalents	(43		)	(72		)
Cash and Cash Equivalents at Beginning of Period	295			137
Cash and Cash Equivalents at End of Period	$	252		$	65
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $4 and $3 capitalized for 2014 and 2013, respectively)	$	61		$	64
Income taxes, net	(28		)	(3		)
Noncash transactions—accrued property additions at end of period	66			30

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

34

ALABAMA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Assets	At March 31, 2014			At December 31, 2013
	(in millions)
Current Assets:
Cash and cash equivalents	$	252		$	295
Receivables —
Customer accounts receivable	363			341
Unbilled revenues	116			142
Other accounts and notes receivable	33			30
Affiliated companies	63			54
Accumulated provision for uncollectible accounts	(8		)	(8		)
Fossil fuel stock, at average cost	230			329
Materials and supplies, at average cost	373			375
Vacation pay	63			63
Prepaid expenses	146			57
Other regulatory assets, current	5			7
Other current assets	13			6
Total current assets	1,649			1,691
Property, Plant, and Equipment:
In service	22,234			22,092
Less accumulated provision for depreciation	8,226			8,114
Plant in service, net of depreciation	14,008			13,978
Nuclear fuel, at amortized cost	342			332
Construction work in progress	829			748
Total property, plant, and equipment	15,179			15,058
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	56			54
Nuclear decommissioning trusts, at fair value	727			714
Miscellaneous property and investments	81			80
Total other property and investments	864			848
Deferred Charges and Other Assets:
Deferred charges related to income taxes	522			519
Prepaid pension costs	279			276
Deferred under recovered regulatory clause revenues	36			25
Other regulatory assets, deferred	707			692
Other deferred charges and assets	126			142
Total deferred charges and other assets	1,670			1,654
Total Assets	$	19,362		$	19,251

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

35

ALABAMA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholder's Equity	At March 31, 2014			At December 31, 2013
	(in millions)
Current Liabilities:
Accounts payable —
Affiliated	$	191		$	198
Other	259			339
Customer deposits	86			85
Accrued taxes —
Accrued income taxes	137			11
Other accrued taxes	57			33
Accrued interest	58			61
Accrued vacation pay	53			53
Accrued compensation	40			74
Other regulatory liabilities, current	36			37
Other current liabilities	39			41
Total current liabilities	956			932
Long-term Debt	6,233			6,233
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	3,623			3,603
Deferred credits related to income taxes	74			75
Accumulated deferred investment tax credits	131			133
Employee benefit obligations	193			195
Asset retirement obligations	741			730
Other cost of removal obligations	843			828
Other regulatory liabilities, deferred	255			259
Deferred over recovered regulatory clause revenues	—			15
Other deferred credits and liabilities	65			61
Total deferred credits and other liabilities	5,925			5,899
Total Liabilities	13,114			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	2,273			2,262
Retained earnings	2,093			2,044
Accumulated other comprehensive loss	(25		)	(26		)
Total common stockholder's equity	5,563			5,502
Total Liabilities and Stockholder's Equity	$	19,362		$	19,251

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

36

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

FIRST QUARTER 2014 vs. FIRST QUARTER 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

First Quarter 2014 vs. First Quarter 2013
(change in millions)	(% change)
$46	32.6

Alabama Power's net income after dividends on preferred and preference stock for the first quarter 2014 was $187 million compared to $141 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

First Quarter 2014 vs. First Quarter 2013
(change in millions)	(% change)
$156	13.7

In the first quarter 2014, retail revenues were $1.30 billion compared to $1.14 billion for the corresponding period in 2013.

37

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Details of the changes in retail revenues were as follows:

	First Quarter 2014
	(in millions)		(% change)
Retail – prior year	$	1,141
Estimated change resulting from –
Rates and pricing	20		1.8
Sales growth	1		—
Weather	52		4.6
Fuel and other cost recovery	83		7.3
Retail – current year	$	1,297	13.7%

Revenues associated with changes in rates and pricing increased in the first quarter 2014 when compared to the corresponding period 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 were not material in the first quarter 2014 when compared to the corresponding period in 2013. Industrial KWH energy sales increased 3.6% in the first quarter 2014 as a result of an increase in demand resulting from changes in production levels primarily in the primary metals, forest products, and automotive and plastics sectors. Weather-adjusted residential and commercial KWH energy sales decreased 0.1% and 0.3%, respectively, in the first quarter 2014 when compared to the corresponding period in 2013.

Revenues resulting from changes in weather increased in the first quarter 2014 due to colder weather experienced in Alabama Power's service territory compared to the corresponding period in 2013. For the first quarter 2014, the resulting increases were 8.1% and 3.6% for residential and commercial sales revenue, respectively.

Fuel and other cost recovery revenues increased in the first quarter 2014 when compared to the corresponding period in 2013 primarily due to an increase in fuel costs associated with an increase in KWH generation and the average cost of fuel. Electric rates include provisions to recognize the full recovery of fuel costs, purchased power costs, PPAs certificated by the Alabama PSC, and costs associated with the NDR. Under these provisions, fuel and other cost recovery revenues generally equal fuel and other cost recovery expenses and do not affect net income.

Wholesale Revenues – Non-Affiliates

First Quarter 2014 vs. First Quarter 2013
(change in millions)	(% change)
$26	44.1

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

In the first quarter 2014, wholesale revenues from sales to non-affiliates were $85 million compared to $59 million for the corresponding period in 2013. The increase was primarily due to a 32.3% increase in KWH sales resulting from increased demand due to colder weather in the first quarter 2014 as compared to the corresponding period in 2013 and an 8.7% increase in the price of energy primarily due to higher natural gas prices.

38

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Wholesale Revenues – Affiliates

First Quarter 2014 vs. First Quarter 2013
(change in millions)	(% change)
$13	23.2

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

In the first quarter 2014, wholesale revenues from sales to affiliates were $69 million compared to $56 million for the corresponding period in 2013. The increase was primarily due to a 27.9% increase in the price of energy primarily due to higher natural gas prices, partially offset by a 4.5% decrease in KWH sales.

Other Revenues

First Quarter 2014 vs. First Quarter 2013
(change in millions)	(% change)
$5	9.6

In the first quarter 2014, other revenues were $57 million compared to $52 million for the corresponding period in 2013. The increase was primarily due to an increase in transmission revenues related to open access transmission agreements.

Fuel and Purchased Power Expenses

	First Quarter 2014 vs. First Quarter 2013
	(change in millions)		(% change)
Fuel	$	60	16.1
Purchased power – non-affiliates	37		185.0
Purchased power – affiliates	18		58.1
Total fuel and purchased power expenses	$	115

In the first quarter 2014, total fuel and purchased power expenses were $538 million compared to $423 million for the corresponding period in 2013. The increase was primarily due to a $31 million increase related to the volume of KWHs generated, as a result of colder weather in the first quarter 2014, a $31 million increase in the volume of KWHs purchased, a $29 million increase in the average cost of fuel primarily due to an increase in the price of natural gas, and a $24 million increase in the average cost of purchased power.

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

39

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

	First Quarter 2014	First Quarter 2013
Total generation (billions of KWHs)	16	16
Total purchased power (billions of KWHs)	2	1
Sources of generation (percent) —
Coal	53	47
Nuclear	23	24
Gas	15	17
Hydro	9	12
Cost of fuel, generated (cents per net KWH) —
Coal	3.40	3.35
Nuclear	0.87	0.81
Gas	4.19	3.31
Average cost of fuel, generated (cents per net KWH)(a)	2.89	2.65
Average cost of purchased power (cents per net KWH)(b)	6.41	4.96

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

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

Fuel

In the first quarter 2014, fuel expense was $432 million compared to $372 million for the corresponding period in 2013. The increase was primarily due to a 26.6% increase in the average cost of natural gas per KWH generated, which excludes fuel associated with tolling agreements, a 15.3% increase in the volume of KWHs generated by coal, and a 19.0% decrease in the volume of KWHs generated by hydro facilities. These increases in fuel expense were offset by a 7.5% decrease in the volume of KWHs generated by natural gas.

Purchased Power – Non-Affiliates

In the first quarter 2014, purchased power expense from non-affiliates was $57 million compared to $20 million for the corresponding period in 2013. The increase was related to a 130.5% increase in the average cost per KWH purchased primarily due to timing of demand during peak periods and a 24.1% 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 first quarter 2014, purchased power expense from affiliates was $49 million compared to $31 million for the corresponding period in 2013. The increase was related to a 108.4% 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 a 23.8% decrease in the average cost per KWH purchased, due to the availability of Southern Company system resources.

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.

40

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Other Operations and Maintenance Expenses

First Quarter 2014 vs. First Quarter 2013
(change in millions)	(% change)
$(5)	(1.5)

In the first quarter 2014, other operations and maintenance expenses were $325 million compared to $330 million for the corresponding period in 2013. In accordance with an accounting order, Alabama Power deferred approximately $25 million of non-nuclear outage expenditures during the first quarter 2014. Alabama Power expensed $16 million in non-nuclear outage costs during the first quarter 2013; therefore, the net impact in the first quarter 2014 was a $16 million decrease in other operations and maintenance expenses. 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. The decrease was partially offset by increases of $7 million in steam production expenses and $4 million in nuclear production expenses primarily related to labor costs.

Depreciation and Amortization

First Quarter 2014 vs. First Quarter 2013
(change in millions)	(% change)
$17	10.8

In the first quarter 2014, depreciation and amortization was $175 million compared to $158 million for the corresponding period in 2013. The increase was 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" 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 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.

Income Taxes

First Quarter 2014 vs. First Quarter 2013
(change in millions)	(% change)
$30	30.9

In the first quarter 2014, income taxes were $127 million compared to $97 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, 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 energy 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

41

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

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). 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. Pending such further proceedings, it is anticipated that CSAPR will remain stayed and the EPA will continue to administer the Clean Air Interstate Rule. The ultimate outcome of this matter 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 Alabama Power in Item 7 of the Form 10-K for additional information regarding the EPA's proposed rule for cooling water intake structures.

On April 16, 2014, the EPA requested an extension of its deadline for issuing a final rule for cooling water intake structures until May 16, 2014.

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.

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.

42

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Other Matters

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

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. Currently, Alabama Power is paying the fee of approximately $13 million annually. 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.

FINANCIAL CONDITION AND LIQUIDITY

Overview

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Alabama Power in Item 7 of the Form 10-K for additional information. Alabama Power's financial condition remained stable at March 31, 2014. Alabama Power intends to continue to monitor its access to short-term

43

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 $352 million for the first three months of 2014, an increase of $82 million as compared to the first three months of 2013. The increase in net cash provided from operating activities was primarily due to changes in timing of fossil fuel stock purchases and tax payments and refunds, partially offset by the timing of collection of fuel cost recovery revenues as compared to the first three months of 2013. Net cash used for investing activities totaled $255 million for the first three months of 2014 primarily due to gross property additions related to distribution, transmission, environmental, and steam generation. Net cash used for financing activities totaled $140 million for the first three months of 2014 primarily due to the payment of common stock dividends. Fluctuations in cash flow from financing activities vary year to year based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes for the first three months of 2014 include increases of $126 million in accrued income taxes and $121 million in property, plant, and equipment, primarily due to additions to distribution, transmission, environmental, and steam generation.

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. There are no requirements through March 31, 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.

44

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

At March 31, 2014, Alabama Power had approximately $252 million of cash and cash equivalents. Committed credit arrangements with banks at March 31, 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)
$	238	$	35	$	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 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 March 31, 2014, Alabama Power had $784 million of outstanding variable rate pollution control revenue bonds requiring liquidity support. In addition, at March 31, 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.

Alabama Power had no commercial paper or short-term debt outstanding during the period ended March 31, 2014.

Management believes that the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, 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 March 31, 2014, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $313 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.

45

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Financing Activities

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

46

GEORGIA POWER COMPANY

47

GEORGIA POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended March 31,
	2014			2013
	(in millions)
Operating Revenues:
Retail revenues	$	2,050		$	1,729
Wholesale revenues, non-affiliates	109			62
Wholesale revenues, affiliates	21			6
Other revenues	89			85
Total operating revenues	2,269			1,882
Operating Expenses:
Fuel	752			519
Purchased power, non-affiliates	79			50
Purchased power, affiliates	184			175
Other operations and maintenance	427			431
Depreciation and amortization	208			200
Taxes other than income taxes	103			95
Total operating expenses	1,753			1,470
Operating Income	516			412
Other Income and (Expense):
Allowance for equity funds used during construction	6			6
Interest expense, net of amounts capitalized	(84		)	(91		)
Other income (expense), net	(2		)	(2		)
Total other income and (expense)	(80		)	(87		)
Earnings Before Income Taxes	436			325
Income taxes	166			124
Net Income	270			201
Dividends on Preferred and Preference Stock	4			4
Net Income After Dividends on Preferred and Preference Stock	$	266		$	197

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended March 31,
	2014		2013
	(in millions)
Net Income	$	270	$	201
Other comprehensive income (loss):
Qualifying hedges:
Reclassification adjustment for amounts included in net income, net of tax of $- and $-, respectively	—		1
Total other comprehensive income (loss)	—		1
Comprehensive Income	$	270	$	202

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

48

GEORGIA POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Three Months Ended March 31,
	2014			2013
	(in millions)
Operating Activities:
Net income	$	270		$	201
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	250			239
Deferred income taxes	96			59
Allowance for equity funds used during construction	(6		)	(6		)
Retail fuel cost over recovery—long-term	(44		)	(58		)
Deferred expenses	33			31
Other, net	(14		)	(27		)
Changes in certain current assets and liabilities —
-Receivables	(83		)	40
-Fossil fuel stock	257			(4		)
-Prepaid income taxes	(11		)	11
-Other current assets	(12		)	42
-Accounts payable	(28		)	78
-Accrued taxes	(166		)	(127		)
-Accrued compensation	(38		)	(66		)
-Retail fuel cost over recovery—short-term	(14		)	10
-Other current liabilities	9			5
Net cash provided from operating activities	499			428
Investing Activities:
Property additions	(460		)	(419		)
Investment of restricted cash	—			(18		)
Nuclear decommissioning trust fund purchases	(175		)	(205		)
Nuclear decommissioning trust fund sales	173			204
Cost of removal, net of salvage	(3		)	(17		)
Change in construction payables, net of joint owner portion	28			(25		)
Prepaid long-term service agreements	(44		)	(5		)
Other investing activities	1			6
Net cash used for investing activities	(480		)	(479		)
Financing Activities:
Increase (decrease) in notes payable, net	(749		)	300
Proceeds —
Capital contributions from parent company	12			11
Pollution control revenue bonds issuances	—			18
Senior notes issuances	—			650
FFB loan	1,000			—
Redemptions —
Senior notes	—			(650		)
Payment of preferred and preference stock dividends	(4		)	(4		)
Payment of common stock dividends	(238		)	(227		)
FFB loan issuance costs	(49		)	(1		)
Other financing activities	(3		)	(12		)
Net cash provided from (used for) financing activities	(31		)	85
Net Change in Cash and Cash Equivalents	(12		)	34
Cash and Cash Equivalents at Beginning of Period	30			45
Cash and Cash Equivalents at End of Period	$	18		$	79
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $3 and $3 capitalized for 2014 and 2013, respectively)	$	71		$	72
Income taxes, net	11			3
Noncash transactions—accrued property additions at end of period	229			212

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

49

GEORGIA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Assets	At March 31, 2014			At December 31, 2013
	(in millions)
Current Assets:
Cash and cash equivalents	$	18		$	30
Receivables —
Customer accounts receivable	523			512
Unbilled revenues	179			209
Joint owner accounts receivable	85			67
Other accounts and notes receivable	69			117
Affiliated companies	21			21
Accumulated provision for uncollectible accounts	(5		)	(5		)
Fossil fuel stock, at average cost	486			742
Materials and supplies, at average cost	409			409
Vacation pay	88			88
Prepaid income taxes	103			97
Other regulatory assets, current	61			66
Other current assets	108			54
Total current assets	2,145			2,407
Property, Plant, and Equipment:
In service	30,295			30,132
Less accumulated provision for depreciation	11,028			10,970
Plant in service, net of depreciation	19,267			19,162
Other utility plant, net	234			240
Nuclear fuel, at amortized cost	532			523
Construction work in progress	3,660			3,500
Total property, plant, and equipment	23,693			23,425
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	47			46
Nuclear decommissioning trusts, at fair value	786			751
Miscellaneous property and investments	43			44
Total other property and investments	876			841
Deferred Charges and Other Assets:
Deferred charges related to income taxes	710			718
Prepaid pension costs	123			118
Deferred under recovered regulatory clause revenues	152			—
Other regulatory assets, deferred	1,207			1,152
Other deferred charges and assets	283			246
Total deferred charges and other assets	2,475			2,234
Total Assets	$	29,189		$	28,907

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

50

GEORGIA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholder's Equity	At March 31, 2014			At December 31, 2013
	(in millions)
Current Liabilities:
Securities due within one year	$	5		$	5
Notes payable	298			1,047
Accounts payable —
Affiliated	440			417
Other	514			472
Customer deposits	249			246
Accrued taxes —
Accrued income taxes	30			—
Other accrued taxes	123			321
Accrued interest	98			91
Accrued vacation pay	60			61
Accrued compensation	51			80
Liabilities from risk management activities	10			13
Nuclear decommissioning trust securities lending collateral	36			9
Other regulatory liabilities, current	22			17
Other current liabilities	160			127
Total current liabilities	2,096			2,906
Long-term Debt	9,632			8,633
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	5,288			5,200
Deferred credits related to income taxes	110			112
Accumulated deferred investment tax credits	200			203
Employee benefit obligations	541			542
Asset retirement obligations	1,196			1,210
Other cost of removal obligations	53			43
Other deferred credits and liabilities	172			201
Total deferred credits and other liabilities	7,560			7,511
Total Liabilities	19,288			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	5,651			5,633
Retained earnings	3,591			3,565
Accumulated other comprehensive loss	(5		)	(5		)
Total common stockholder's equity	9,635			9,591
Total Liabilities and Stockholder's Equity	$	29,189		$	28,907

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

51

GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

FIRST QUARTER 2014 vs. FIRST QUARTER 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

First Quarter 2014 vs. First Quarter 2013
(change in millions)	(% change)
$69	35.0

Georgia Power's net income after dividends on preferred and preference stock for the first quarter 2014 was $266 million compared to $197 million for the corresponding period in 2013. The increase was primarily due to colder weather in the first quarter 2014 as compared to the corresponding period in 2013 and an increase in retail base revenues effective January 1, 2014 as authorized under the 2013 ARP, partially offset by an increase in income taxes.

Retail Revenues

First Quarter 2014 vs. First Quarter 2013
(change in millions)	(% change)
$321	18.6

In the first quarter 2014, retail revenues were $2.05 billion compared to $1.73 billion for the corresponding period in 2013.

52

GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Details of the changes in retail revenues were as follows:

	First Quarter 2014
	(in millions)		(% change)
Retail – prior year	$	1,729
Estimated change resulting from –
Rates and pricing	40		2.3
Sales growth	11		0.6
Weather	52		3.1
Fuel cost recovery	218		12.6
Retail – current year	$	2,050	18.6%

Revenues associated with changes in rates and pricing increased in the first quarter 2014 when compared to the corresponding period in 2013 primarily due to base tariff increases effective January 1, 2014, as approved by the Georgia PSC in the 2013 ARP, and collecting 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 first quarter 2014 when compared to the corresponding period in 2013. Weather-adjusted residential KWH sales increased 2.2%, weather-adjusted commercial KWH sales decreased 0.4%, and weather-adjusted industrial KWH sales increased 1.0% in the first quarter 2014 when compared to the corresponding period in 2013. An increase of 17,050 residential customers since March 31, 2013 contributed to the increase in weather-adjusted residential KWH sales. Increased demand in the primary metals, non-manufacturing, stone, clay, and glass, and textiles 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 $218 million in the first quarter 2014 when compared to the corresponding period in 2013 due to higher fuel 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

First Quarter 2014 vs. First Quarter 2013
(change in millions)	(% change)
$47	75.8

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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In the first quarter 2014, wholesale revenues from sales to non-affiliates were $109 million compared to $62 million in the corresponding period in 2013 due to increased demand resulting from colder weather in the first quarter 2014 as compared to the corresponding period in 2013 and the lower cost of Georgia Power-owned generation.

Wholesale Revenues – Affiliates

First Quarter 2014 vs. First Quarter 2013
(change in millions)	(% change)
$15	250.0

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 first quarter 2014, wholesale revenues from affiliates were $21 million compared to $6 million in the corresponding period in 2013. The increase was due to higher demand resulting from colder weather in 2014 as compared to the corresponding period in 2013 and the lower cost of Georgia Power-owned generation.

Fuel and Purchased Power Expenses

	First Quarter 2014 vs. First Quarter 2013
	(change in millions)		(% change)
Fuel	$	233	44.9
Purchased power – non-affiliates	29		58.0
Purchased power – affiliates	9		5.1
Total fuel and purchased power expenses	$	271

In the first quarter 2014, total fuel and purchased power expenses were $1.02 billion compared to $744 million in the corresponding period in 2013. The increase in the first quarter 2014 was primarily due to a $116 million increase in the average cost of fuel and purchased power primarily due to higher natural gas prices and a $155 million increase primarily in the volume of KWHs generated as a result of colder weather 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.

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

	First Quarter 2014	First Quarter 2013
Total generation (billions of KWHs)	18	15
Total purchased power (billions of KWHs)	5	6
Sources of generation (percent) —
Coal	48	29
Nuclear	20	22
Gas	29	46
Hydro	3	3
Cost of fuel, generated (cents per net KWH) —
Coal	5.03	5.28
Nuclear	0.91	0.90
Gas	4.39	3.14
Average cost of fuel, generated (cents per net KWH)	3.99	3.28
Average cost of purchased power (cents per net KWH)(a)	5.75	4.44

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

Fuel

In the first quarter 2014, fuel expense was $752 million compared to $519 million in the corresponding period in 2013. The increase was primarily due to a 21.4% increase in the volume of KWHs generated as a result of higher demand and a 21.7% increase in the average cost of fuel per KWH generated primarily due to higher natural gas prices and additional costs associated with increased coal-fired generation.

Purchased Power – Non-Affiliates

In the first quarter 2014, purchased power expense from non-affiliates was $79 million compared to $50 million in the corresponding period in 2013. The increase was due to a 27.1% increase in the volume of KWHs purchased to meet the demand resulting from colder weather in the first quarter 2014 compared to the corresponding period in 2013 and an increase of 25.3% in the average cost per KWH purchased 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 first quarter 2014, purchased power expense from affiliates was $184 million compared to $175 million in the corresponding period in 2013. The increase was due to a 22.8% increase in the average cost per KWH purchased reflecting higher natural gas prices, partially offset by a 14.2% decrease in the volume of KWHs purchased, as Georgia Power units generally dispatched at a lower cost than other Southern Company system resources.

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

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Other Operations and Maintenance Expenses

First Quarter 2014 vs. First Quarter 2013
(change in millions)	(% change)
$(4)	(0.9)

In the first quarter 2014, other operations and maintenance expenses were $427 million compared to $431 million in the corresponding period in 2013. The decrease was due to a decrease of $12 million in pension and other employee-benefit related expenses, partially offset by a $6 million increase in litigation expense and a $3 million increase in the storm damage accrual as authorized in the 2013 ARP.

Depreciation and Amortization

First Quarter 2014 vs. First Quarter 2013
(change in millions)	(% change)
$8	4.0

In the first quarter 2014, depreciation and amortization was $208 million compared to $200 million in the corresponding period in 2013. The increase was primarily 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 $6 million in depreciation and amortization also as authorized in the 2013 ARP.

Taxes Other Than Income Taxes

First Quarter 2014 vs. First Quarter 2013
(change in millions)	(% change)
$8	8.4

In the first quarter 2014, taxes other than income taxes were $103 million compared to $95 million in the corresponding period in 2013. The increase was due to an $8 million increase in municipal franchise fees related to higher retail revenues in 2014.

Interest Expense, Net of Amounts Capitalized

First Quarter 2014 vs. First Quarter 2013
(change in millions)	(% change)
$(7)	(7.7)

In the first quarter 2014, interest expense, net of amounts capitalized was $84 million compared to $91 million in the corresponding period in 2013. The decrease was due to a $10 million decrease in interest on long-term debt resulting from maturities and early redemptions, partially offset by $4 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.

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Income Taxes

First Quarter 2014 vs. First Quarter 2013
(change in millions)	(% change)
$42	33.9

In the first quarter 2014, income taxes were $166 million compared to $124 million in the corresponding period in 2013. The increase was due to higher pre-tax earnings in 2014.

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 operation of ongoing construction projects, primarily Plant Vogtle Units 3 and 4. Future earnings in the near term will depend, in part, upon maintaining energy 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. 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. 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. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively affect results of operations, cash flows, and financial condition. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under "Environmental Matters" in Item 8 of the Form 10-K for additional information.

Environmental Statutes and Regulations

Air Quality

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Air Quality" of Georgia Power in Item 7 of the Form 10-K for additional information regarding the Cross State Air Pollution Rule (CSAPR). 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. Pending such further proceedings, it is anticipated that CSAPR will remain stayed and the EPA will continue to administer the Clean Air Interstate Rule. The ultimate outcome of this matter cannot be determined at this time.

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Water Quality

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

On April 16, 2014, the EPA requested an extension of its deadline for issuing a final rule for cooling water intake structures until May 16, 2014.

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.

PSC Matters

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 March 31, 2014, Georgia Power's under recovered fuel balance totaled $157 million and is included in current assets and other deferred charges and assets on Georgia Power's Condensed Balance Sheet herein. 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

Georgia Power defers and recovers certain costs related to damages from major storms as mandated by the Georgia PSC. As of March 31, 2014 and December 31, 2013, the balance in the regulatory asset related to storm damage was $110 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

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recovered on all applicable certified costs through annual adjustments to an 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 March 31, 2014, approximately $32 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 commercial operation date 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 expects to resume filing semi-annual VCM reports in 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). The portion of additional costs claimed by the Contractor 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. 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. 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. While litigation has commenced 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

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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 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.

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. Currently, Georgia Power is paying the fee of approximately $15 million annually based on its ownership interest. The ultimate outcome of this matter cannot be determined at this time.

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ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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

FINANCIAL CONDITION AND LIQUIDITY

Overview

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Georgia Power in Item 7 of the Form 10-K for additional information. Georgia Power's financial condition remained stable at March 31, 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 $499 million for the first three months of 2014 compared to $428 million for the corresponding period in 2013. The increase was primarily due to higher retail operating revenues and lower fuel inventory additions, partially offset by fuel cost recovery and storm restoration costs. Net cash used for investing activities was essentially the same for first quarters 2014 and 2013. Net cash used for financing activities totaled $31 million for the first three months of 2014 compared to $85 million provided from financing activities in the corresponding period in 2013. The increase in cash used for financing activities is primarily due to FFB loan issuance costs and a decrease in short-term debt, partially offset by borrowings from the FFB for the construction of Plant Vogtle Units 3 and 4. Fluctuations in cash flow from financing activities vary from year to year based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes for the first three months of 2014 include an increase of $999 million in long-term debt primarily due to borrowings from the FFB and decreases of $749 million in short-term debt and $256 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 March 31, 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 cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm

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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 additional information.

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% 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. 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.

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 March 31, 2014, Georgia Power had approximately $18 million of cash and cash equivalents. Committed credit arrangements with banks at March 31, 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.

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 March 31, 2014 was approximately $862 million. In

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

addition, at March 31, 2014, Georgia Power had $242 million of fixed rate pollution control revenue bonds that were required to be remarketed within the next 12 months. Subsequent to March 31, 2014, $197 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.

These committed 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 March 31, 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	$	298	0.2%	$	371	0.2%	$	648
Short-term bank debt	—		—%	227		0.9%	400
Total	$	298	0.2%	$	598	0.4%

(a) Average and maximum amounts are based upon daily balances during the three-month period ended March 31, 2014.

Management believes that the need for working capital can be adequately met by utilizing the commercial paper program, lines of credit, 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 March 31, 2014 were as follows:

Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB- and/or Baa3	$	88
Below BBB- and/or Baa3	1,313

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.

63

GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 will 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 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.

64

GULF POWER COMPANY

65

GULF POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended March 31,
	2014			2013
	(in thousands)
Operating Revenues:
Retail revenues	$	303,120		$	259,877
Wholesale revenues, non-affiliates	35,592			21,208
Wholesale revenues, affiliates	52,778			29,455
Other revenues	15,642			15,734
Total operating revenues	407,132			326,274
Operating Expenses:
Fuel	168,422			120,846
Purchased power, non-affiliates	15,461			11,135
Purchased power, affiliates	6,504			3,312
Other operations and maintenance	84,201			78,662
Depreciation and amortization	31,857			37,053
Taxes other than income taxes	26,799			23,626
Total operating expenses	333,244			274,634
Operating Income	73,888			51,640
Other Income and (Expense):
Allowance for equity funds used during construction	2,379			1,134
Interest expense, net of amounts capitalized	(13,264		)	(14,369		)
Other income (expense), net	(725		)	(976		)
Total other income and (expense)	(11,610		)	(14,211		)
Earnings Before Income Taxes	62,278			37,429
Income taxes	23,284			14,086
Net Income	38,994			23,343
Dividends on Preference Stock	2,251			1,551
Net Income After Dividends on Preference Stock	$	36,743		$	21,792

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended March 31,
	2014		2013
	(in thousands)
Net Income	$	38,994	$	23,343
Other comprehensive income (loss):
Qualifying hedges:
Reclassification adjustment for amounts included in net income, net of tax of $58 and $90, respectively	93		143
Total other comprehensive income (loss)	93		143
Comprehensive Income	$	39,087	$	23,486

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

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GULF POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Three Months Ended March 31,
	2014			2013
	(in thousands)
Operating Activities:
Net income	$	38,994		$	23,343
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	33,764			38,794
Deferred income taxes	14,287			16,777
Allowance for equity funds used during construction	(2,379		)	(1,134		)
Pension, postretirement, and other employee benefits	1,553			2,889
Stock based compensation expense	734			669
Other, net	503			2,485
Changes in certain current assets and liabilities —
-Receivables	(25,275		)	(2,305		)
-Prepayments	1,126			934
-Fossil fuel stock	46,267			1,423
-Materials and supplies	(167		)	(513		)
-Prepaid income taxes	10,495			(7,667		)
-Other current assets	(422		)	—
-Accounts payable	5,746			(17,812		)
-Accrued taxes	9,110			5,380
-Accrued compensation	(4,801		)	(9,451		)
-Over recovered regulatory clause revenues	5,490			(10,186		)
-Other current liabilities	7,125			6,073
Net cash provided from operating activities	142,150			49,699
Investing Activities:
Property additions	(78,789		)	(66,696		)
Cost of removal, net of salvage	(3,059		)	(3,469		)
Change in construction payables	1,129			1,787
Payments pursuant to long-term service agreements	(2,127		)	(1,558		)
Other investing activities	97			243
Net cash used for investing activities	(82,749		)	(69,693		)
Financing Activities:
Increase (decrease) in notes payable, net	(75,388		)	5,809
Proceeds —
Common stock issued to parent	50,000			40,000
Capital contributions from parent company	668			556
Payment of preference stock dividends	(2,251		)	(1,551		)
Payment of common stock dividends	(30,800		)	(28,850		)
Other financing activities	(27		)	(206		)
Net cash provided from (used for) financing activities	(57,798		)	15,758
Net Change in Cash and Cash Equivalents	1,603			(4,236		)
Cash and Cash Equivalents at Beginning of Period	21,753			32,167
Cash and Cash Equivalents at End of Period	$	23,356		$	27,931
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $1,262 and $601 capitalized for 2014 and 2013, respectively)	$	4,630		$	8,306
Income taxes, net	(5,839		)	3,886
Noncash transactions — accrued property additions at end of period	33,186			22,462

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

67

GULF POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Assets	At March 31, 2014			At December 31, 2013
	(in thousands)
Current Assets:
Cash and cash equivalents	$	23,356		$	21,753
Receivables —
Customer accounts receivable	70,386			64,884
Unbilled revenues	50,447			57,282
Under recovered regulatory clause revenues	62,169			48,282
Other accounts and notes receivable	11,421			8,620
Affiliated companies	18,147			8,259
Accumulated provision for uncollectible accounts	(995		)	(1,131		)
Fossil fuel stock, at average cost	88,783			135,050
Materials and supplies, at average cost	55,102			54,935
Other regulatory assets, current	16,722			18,536
Prepaid expenses	11,602			33,186
Other current assets	12,206			6,120
Total current assets	419,346			455,776
Property, Plant, and Equipment:
In service	4,390,454			4,363,664
Less accumulated provision for depreciation	1,232,745			1,211,336
Plant in service, net of depreciation	3,157,709			3,152,328
Construction work in progress	325,001			280,626
Total property, plant, and equipment	3,482,710			3,432,954
Other Property and Investments	15,119			15,314
Deferred Charges and Other Assets:
Deferred charges related to income taxes	52,017			50,597
Prepaid pension costs	11,569			11,533
Other regulatory assets, deferred	345,956			340,415
Other deferred charges and assets	33,006			30,982
Total deferred charges and other assets	442,548			433,527
Total Assets	$	4,359,723		$	4,337,571

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

68

GULF POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholder's Equity	At March 31, 2014			At December 31, 2013
	(in thousands)
Current Liabilities:
Securities due within one year	$	75,000		$	75,000
Notes payable	60,489			135,878
Accounts payable —
Affiliated	88,507			76,897
Other	42,814			47,038
Customer deposits	34,508			34,433
Accrued taxes —
Accrued income taxes	5,166			45
Other accrued taxes	13,031			7,486
Accrued interest	17,959			10,272
Accrued compensation	6,856			11,657
Other regulatory liabilities, current	19,283			13,408
Liabilities from risk management activities	3,804			6,470
Other current liabilities	22,537			22,972
Total current liabilities	389,954			441,556
Long-term Debt	1,158,305			1,158,163
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	743,992			734,355
Accumulated deferred investment tax credits	3,737			4,055
Employee benefit obligations	76,549			76,338
Other cost of removal obligations	225,580			228,148
Other regulatory liabilities, deferred	54,935			56,051
Deferred capacity expense	190,795			180,149
Other deferred credits and liabilities	76,793			77,126
Total deferred credits and other liabilities	1,372,381			1,356,222
Total Liabilities	2,920,640			2,955,941
Preference Stock	146,504			146,504
Common Stockholder's Equity:
Common stock, without par value—
Authorized — 20,000,000 shares
Outstanding — March 31, 2014: 5,442,717 shares
— December 31, 2013: 4,942,717 shares	483,060			433,060
Paid-in capital	554,098			552,681
Retained earnings	256,437			250,494
Accumulated other comprehensive loss	(1,016		)	(1,109		)
Total common stockholder's equity	1,292,579			1,235,126
Total Liabilities and Stockholder's Equity	$	4,359,723		$	4,337,571

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

69

GULF POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

FIRST QUARTER 2014 vs. FIRST QUARTER 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

First Quarter 2014 vs. First Quarter 2013
(change in millions)	(% change)
$14.9	68.6

Gulf Power's net income after dividends on preference stock for the first quarter 2014 was $36.7 million compared to $21.8 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 as compared to the corresponding period in 2013, partially offset by higher income taxes.

Retail Revenues

First Quarter 2014 vs. First Quarter 2013
(change in millions)	(% change)
$43.2	16.6

In the first quarter 2014, retail revenues were $303.1 million compared to $259.9 million for the corresponding period in 2013.

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GULF POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Details of the changes in retail revenues were as follows:

	First Quarter 2014
	(in millions)		(% change)
Retail – prior year	$	259.9
Estimated change resulting from –
Rates and pricing	11.6		4.5
Sales growth	2.1		0.8
Weather	9.4		3.6
Fuel and other cost recovery	20.1		7.7
Retail – current year	$	303.1	16.6%

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 first quarter 2014 when compared to the corresponding period 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 increased in the first quarter 2014 when compared to the corresponding period in 2013. Weather-adjusted KWH energy sales to residential customers increased 0.9% primarily due to customer growth. Weather-adjusted KWH energy sales to commercial customers decreased 1.0% primarily due to a decline in weather-adjusted use per customer, partially offset by customer growth. KWH energy sales to industrial customers increased 12.1% primarily due to decreased customer co-generation.

Fuel and other cost recovery revenues increased in the first quarter 2014 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" herein for additional information.

Wholesale Revenues – Non-Affiliates

First Quarter 2014 vs. First Quarter 2013
(change in millions)	(% change)
$14.4	67.8

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

71

GULF POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

In the first quarter 2014, wholesale revenues from sales to non-affiliates were $35.6 million compared to $21.2 million for the corresponding period in 2013. The increase was primarily due to higher energy revenues related to a 354.8% increase in KWH sales due to lower priced energy supply alternatives from the Southern Company system's resources as compared to market prices in wholesale markets. This increase was partially offset by a 20.4% decrease in the average price of energy sold to non-affiliates in the first quarter 2014 due to higher sales volume under long-term sales agreements and cost-based rates.

Wholesale Revenues – Affiliates

First Quarter 2014 vs. First Quarter 2013
(change in millions)	(% change)
$23.3	79.2

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

In the first quarter 2014, wholesale revenues from sales to affiliates were $52.8 million compared to $29.5 million for the corresponding period in 2013. The increase was primarily due to a 52.9% increase in the price of energy sold to affiliates due to the higher cost of Gulf Power gas-fired resources dispatched to serve the Southern Company system's loads during peak times and a 17.1% increase in KWH sales that resulted from more Gulf Power generation being dispatched to serve affiliated companies' higher weather-related energy demand in the first quarter 2014.

Fuel and Purchased Power Expenses

	First Quarter 2014 vs. First Quarter 2013
	(change in millions)		(% change)
Fuel	$	47.5	39.4
Purchased power – non-affiliates	4.4		38.9
Purchased power – affiliates	3.2		96.4
Total fuel and purchased power expenses	$	55.1

In the first quarter 2014, total fuel and purchased power expenses were $190.4 million compared to $135.3 million for the corresponding period in 2013. The increase was primarily due to a $43.6 million increase in the volume of KWHs generated and purchased as a result of colder weather increasing customer demand and an $11.5 million increase due to the change in the 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.

72

GULF POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

	First Quarter 2014	First Quarter 2013
Total generation (millions of KWHs)	2,962	1,861
Total purchased power (millions of KWHs)	1,430	1,663
Sources of generation (percent) –
Coal	70	52
Gas	30	48
Cost of fuel, generated (cents per net KWH) –
Coal(a)	4.31	4.68
Gas	3.66	3.72
Average cost of fuel, generated (cents per net KWH)	4.11	4.22
Average cost of purchased power (cents per net KWH)(a)	4.79	3.42

(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 first quarter 2014, fuel expense was $168.4 million compared to $120.9 million for the corresponding period in 2013. The increase was primarily due to a 59.2% increase in the volume of KWHs generated due to a higher utilization of coal-fired generation to meet the Southern Company system's demand related to colder weather in the first quarter 2014 compared to the corresponding period in 2013. The increase was partially offset by a 2.6% decrease in the average cost of fuel due to lower coal prices.

Purchased Power – Non-Affiliates

In the first quarter 2014, purchased power expense from non-affiliates was $15.5 million compared to $11.1 million for the corresponding period in 2013. The increase was primarily due to a 47.4% increase in the average cost per KWH purchased, partially offset by a 21.2% decrease in the volume of KWHs purchased due to colder regional weather conditions 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 first quarter 2014, purchased power expense from affiliates was $6.5 million compared to $3.3 million for the corresponding period in 2013. The increase was primarily due to a 177.1% increase in the volume of KWHs purchased due to colder weather driving higher demand in the first quarter 2014, partially offset by a 33.8% decrease in the average cost per KWH purchased.

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

73

GULF POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Other Operations and Maintenance Expenses

First Quarter 2014 vs. First Quarter 2013
(change in millions)	(% change)
$5.6	7.0

In the first quarter 2014, other operations and maintenance expenses were $84.2 million compared to $78.6 million for the corresponding period in 2013. The increase was primarily due to an increase of $8.1 million in routine and planned maintenance expenses at generation and distribution facilities, partially offset by decreases of $1.5 million in pension and other benefit-related expenses, $1.2 million in other energy services expenses, and $1.1 million in marketing programs.

The decreased expenses from other energy services did not have a significant impact on earnings since they were generally offset by associated revenues. The decreased expense from marketing programs did not have a significant impact on earnings since the expense was offset by energy conservation revenues through Gulf Power's energy conservation cost recovery clause. 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.

Depreciation and Amortization

First Quarter 2014 vs. First Quarter 2013
(change in millions)	(% change)
$(5.2)	(14.0)

In the first quarter 2014, depreciation and amortization was $31.8 million compared to $37.0 million for the corresponding period in 2013. The decrease was primarily due to reductions of $6.2 million in depreciation as approved by the Florida PSC in a 2013 rate order. Under the terms of the order, Gulf Power may record a reduction in depreciation in an amount necessary to reach the mid-point of the authorized ROE range. 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

First Quarter 2014 vs. First Quarter 2013
(change in millions)	(% change)
$3.2	13.4

In the first quarter 2014, taxes other than income taxes were $26.8 million compared to $23.6 million for the corresponding period in 2013. The increase was primarily due to increases of $1.6 million in franchise fees and $1.4 million in gross receipts taxes as a result of higher retail revenues. Franchise fees and gross receipts taxes have no impact on net income.

74

GULF POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Income Taxes

First Quarter 2014 vs. First Quarter 2013
(change in millions)	(% change)
$9.2	65.3

In the first quarter 2014, income taxes were $23.3 million compared to $14.1 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 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.

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GULF 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 Gulf Power in Item 7 of the Form 10-K for additional information regarding the Cross State Air Pollution Rule (CSAPR). 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. Pending such further proceedings, it is anticipated that CSAPR will remain stayed and the EPA will continue to administer the Clean Air Interstate Rule. The ultimate outcome of this matter 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 Gulf Power in Item 7 of the Form 10-K for additional information regarding the EPA's proposed rule for cooling water intake structures.

On April 16, 2014, the EPA requested an extension of its deadline for issuing a final rule for cooling water intake structures until May 16, 2014.

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.

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 ROE range then in effect. In the first quarter 2014, Gulf Power recognized a reduction in depreciation expense of $6.2 million.

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.

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

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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 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.

FINANCIAL CONDITION AND LIQUIDITY

Overview

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Gulf Power in Item 7 of the Form 10-K for additional information. Gulf Power's financial condition remained stable at March 31, 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 $142.2 million for the first three months of 2014 compared to $49.7 million for the corresponding period in 2013. The $92.5 million increase in net cash was primarily due to a decrease in fossil fuel stock resulting from an increase in KWH generation, an increase in accounts payable, an increase in net income, and a decrease in prepaid income taxes. Net cash used for investing activities totaled $82.7 million in the first three months of 2014 primarily due to property additions to utility plant. Net cash used for financing activities totaled $57.8 million for the first three months of 2014 primarily due to the repayment of short-term debt and the payment of common stock dividends, partially offset by the issuance of common stock to Southern Company. Fluctuations in cash flow from financing activities vary from year to year based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes for the first three months of 2014 include a net increase of $49.8 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 $75.4 million in notes payable due to reductions in commercial paper and $46.3 million in fossil fuel stock.

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Capital Requirements and Contractual Obligations

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Gulf Power in Item 7 of the Form 10-K for a description of Gulf Power's capital requirements for its construction program, including estimated capital expenditures to comply with existing environmental statutes and regulations, scheduled maturities of long-term debt, as well as related interest, leases, derivative obligations, preference stock dividends, purchase commitments, trust funding requirements, and unrecognized tax benefits. Approximately $104.1 million will be required through March 31, 2015 to fund maturities and announced redemptions 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 March 31, 2014, Gulf Power had approximately $23.4 million of cash and cash equivalents. Committed credit arrangements with banks at March 31, 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)
$	75	$	35	$	165	$	275	$	275	$	50	$	—	$	50	$	60

(a) No credit arrangements expire in 2017 or 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 March 2014, Gulf Power renewed two credit arrangements, one for $30 million and one for $5 million, which will expire in March

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2015. In addition, the $5 million credit arrangement was modified to include a one-year term out provision. 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 March 31, 2014 was approximately $69 million. In addition, at March 31, 2014, Gulf Power had $37.0 million of fixed rate pollution control revenue bonds that were remarketed to the public in April 2014and currently are not 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 March 31, 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	$	61	0.2%	$	94	0.2%	$	143

(a) Average and maximum amounts are based upon daily balances during the three-month period ended March 31, 2014.

Management believes that the need for working capital can be adequately met by utilizing the commercial paper program, lines of credit, 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 March 31, 2014 were as follows:

Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB- and/or Baa3	$	92
Below BBB- and/or Baa3	430

Included in these amounts are certain agreements that could require collateral in the event that one or more Southern Company system power pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact Gulf Power's ability to access capital markets, particularly the short-term debt market and the variable rate pollution control revenue bond market.

Market Price Risk

Gulf Power's market risk exposure relative to interest rate changes for the first quarter 2014 has not changed materially compared to the December 31, 2013 reporting period. In addition, Gulf Power's exposure to market volatility in commodity fuel prices and prices of electricity with respect to its wholesale generating capacity is

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limited because its long-term sales agreements shift substantially all fuel cost responsibility to the purchaser. However, Gulf Power could become exposed to market volatility in energy-related commodity prices to the extent any wholesale generating capacity is uncontracted. 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.

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.

Subsequent to March 31, 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 will be used for the announced redemption, on May 15, 2014, of $29.075 million aggregate principal amount of MBFC Pollution Control Revenue Refunding Bonds, Series 2003 (Gulf Power Company Project).

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

CONDENSED STATEMENTS OF OPERATIONS (UNAUDITED)

	For the Three Months Ended March 31,
	2014			2013
	(in thousands)
Operating Revenues:
Retail revenues	$	207,038		$	168,310
Wholesale revenues, non-affiliates	96,718			65,109
Wholesale revenues, affiliates	22,789			8,341
Other revenues	4,616			4,174
Total operating revenues	331,161			245,934
Operating Expenses:
Fuel	146,951			104,564
Purchased power, non-affiliates	11,494			1,367
Purchased power, affiliates	8,929			9,689
Other operations and maintenance	66,095			54,812
Depreciation and amortization	22,694			23,233
Taxes other than income taxes	20,458			19,417
Estimated loss on Kemper IGCC	380,000			462,000
Total operating expenses	656,621			675,082
Operating Income (Loss)	(325,460		)	(429,148		)
Other Income and (Expense):
Allowance for equity funds used during construction	38,082			26,074
Interest expense, net of amounts capitalized	(12,035		)	(10,409		)
Other income (expense), net	(1,799		)	(1,547		)
Total other income and (expense)	24,248			14,118
Earnings (Loss) Before Income Taxes	(301,212		)	(415,030		)
Income taxes (benefit)	(129,597		)	(169,142		)
Net Income (Loss)	(171,615		)	(245,888		)
Dividends on Preferred Stock	433			433
Net Income (Loss) After Dividends on Preferred Stock	$	(172,048	)	$	(246,321	)

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (UNAUDITED)

	For the Three Months Ended March 31,
	2014			2013
	(in thousands)
Net Income (Loss)	$	(171,615	)	$	(245,888	)
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 $131 and $131, respectively	212			212
Total other comprehensive income (loss)	211			212
Comprehensive Income (Loss)	$	(171,404	)	$	(245,676	)

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 Three Months Ended March 31,
	2014			2013
	(in thousands)
Operating Activities:
Net income (loss)	$	(171,615	)	$	(245,888	)
Adjustments to reconcile net income (loss)   to net cash provided from (used for) operating activities —
Depreciation and amortization, total	24,035			21,692
Deferred income taxes	(124,158		)	(174,082		)
Investment tax credits received	2,626			—
Allowance for equity funds used during construction	(38,082		)	(26,074		)
Pension, postretirement, and other employee benefits	1,037			2,926
Stock based compensation expense	1,324			1,033
Regulatory assets associated with Kemper IGCC	(13,226		)	(6,843		)
Estimated loss on Kemper IGCC	380,000			462,000
Kemper regulatory deferral	34,342			—
Other, net	2,555			(628		)
Changes in certain current assets and liabilities —
-Receivables	(13,525		)	(5,226		)
-Fossil fuel stock	36,595			8,415
-Materials and supplies	(2,970		)	(4,744		)
-Prepaid income taxes	(32,720		)	1,573
-Other current assets	(2,000		)	(2,389		)
-Accounts payable	14,900			(13,783		)
-Accrued taxes	(54,996		)	(45,429		)
-Accrued interest	8,225			6,570
-Accrued compensation	(2,080		)	(10,247		)
-Over recovered regulatory clause revenues	(18,358		)	2,996
-Other current liabilities	293			2,971
Net cash provided from (used for) operating activities	32,202			(25,157		)
Investing Activities:
Property additions	(323,816		)	(369,313		)
Cost of removal, net of salvage	(3,997		)	(902		)
Construction payables	(30,519		)	23,150
Capital grant proceeds	—			1,784
Other investing activities	(3,100		)	(7,145		)
Net cash used for investing activities	(361,432		)	(352,426		)
Financing Activities:
Proceeds —
Capital contributions from parent company	687			100,552
Bonds-Other	—			15,814
Interest-bearing refundable deposit related to asset sale	75,000			—
Other long-term debt issuances	250,000			350,000
Redemptions — Capital leases	(623		)	—
Payment of preferred stock dividends	(433		)	(433		)
Payment of common stock dividends	—			(44,190		)
Return of capital	(54,930		)	—
Other financing activities	(454		)	(1,409		)
Net cash provided from financing activities	269,247			420,334
Net Change in Cash and Cash Equivalents	(59,983		)	42,751
Cash and Cash Equivalents at Beginning of Period	145,165			145,008
Cash and Cash Equivalents at End of Period	$	85,182		$	187,759
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (paid $16,903 and $16,001, net of $13,875 and $11,141 capitalized for 2014 and 2013, respectively)	$	3,028		$	4,860
Income taxes, net	26,078			(25		)
Noncash transactions — accrued property additions at end of period	132,065			238,013

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

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MISSISSIPPI POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Assets	At March 31, 2014			At December 31, 2013
	(in thousands)
Current Assets:
Cash and cash equivalents	$	85,182		$	145,165
Receivables —
Customer accounts receivable	40,722			40,978
Unbilled revenues	37,363			38,895
Under recovered regulatory clause revenues	2,146			—
Other accounts and notes receivable	3,853			4,600
Affiliated companies	48,835			34,920
Accumulated provision for uncollectible accounts	(2,113		)	(3,018		)
Fossil fuel stock, at average cost	76,689			113,285
Materials and supplies, at average cost	48,317			45,347
Other regulatory assets, current	53,416			52,496
Prepaid income taxes	60,355			34,751
Other current assets	13,525			9,357
Total current assets	468,290			516,776
Property, Plant, and Equipment:
In service	3,467,314			3,458,770
Less accumulated provision for depreciation	1,108,649			1,095,352
Plant in service, net of depreciation	2,358,665			2,363,418
Construction work in progress	2,550,361			2,586,031
Total property, plant, and equipment	4,909,026			4,949,449
Other Property and Investments	4,909			4,857
Deferred Charges and Other Assets:
Deferred charges related to income taxes	158,788			139,834
Other regulatory assets, deferred	212,467			200,620
Accumulated deferred income taxes	34,533			—
Other deferred charges and assets	39,899			36,673
Total deferred charges and other assets	445,687			377,127
Total Assets	$	5,827,912		$	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 March 31, 2014			At December 31, 2013
	(in thousands)
Current Liabilities:
Securities due within one year	$	313,821		$	13,789
Interest-bearing refundable deposit related to asset sale	225,000			150,000
Accounts payable —
Affiliated	74,332			70,299
Other	190,538			210,191
Customer deposits	14,867			14,379
Accrued taxes —
Accrued income taxes	3,222			5,590
Other accrued taxes	26,020			77,958
Accrued interest	55,369			47,144
Accrued compensation	7,244			9,324
Other regulatory liabilities, current	38,316			24,981
Over recovered regulatory clause liabilities	—			18,358
Other current liabilities	19,767			21,413
Total current liabilities	968,496			663,426
Long-term Debt	2,114,184			2,167,067
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	—			72,808
Deferred credits related to income taxes	7,873			9,145
Accumulated deferred investment tax credits	283,959			284,248
Employee benefit obligations	94,116			94,430
Asset retirement obligations	41,682			41,197
Other cost of removal obligations	156,426			151,340
Other regulatory liabilities, deferred	162,997			140,880
Other deferred credits and liabilities	14,128			14,337
Total deferred credits and other liabilities	761,181			808,385
Total Liabilities	3,843,861			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	2,323,151			2,376,595
Retained earnings (deficit)	(401,919		)	(229,871		)
Accumulated other comprehensive loss	(7,652		)	(7,864		)
Total common stockholder's equity	1,951,271			2,176,551
Total Liabilities and Stockholder's Equity	$	5,827,912		$	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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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

FIRST QUARTER 2014 vs. FIRST QUARTER 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.

On April 28, 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. However, as a result of the construction issues described above, as well as the risk of additional factors that have the potential to further extend construction and start-up as described herein, the in-service date for the remainder of the Kemper IGCC is currently expected to occur in the first half of 2015. The revised cost estimate above includes costs through May 31, 2015. Any further extension of the in-service date is estimated to result in additional costs of approximately $25 million per month.

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 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

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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 the first quarter 2014 as compared to the target.

RESULTS OF OPERATIONS

Net Income (Loss)

First Quarter 2014 vs. First Quarter 2013
(change in millions)	(% change)
$74.3	30.2

Mississippi Power's net loss after dividends on preferred stock for the first quarter 2014 was $172.0 million compared to $246.3 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 2014 compared to a $462.0 million pre-tax charge ($285.3 million after tax) in 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 a 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

First Quarter 2014 vs. First Quarter 2013
(change in millions)	(% change)
$38.7	23.0

In the first quarter 2014, retail revenues were $207.0 million compared to $168.3 million for the corresponding period in 2013.

Details of the changes in retail revenues were as follows:

	First Quarter 2014
	(in millions)		(% change)
Retail – prior year	$	168.3
Estimated change resulting from –
Rates and pricing	11.9		7.0
Sales growth	1.0		0.6
Weather	2.4		1.5
Fuel and other cost recovery	23.4		13.9
Retail – current year	$	207.0	23.0%

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Revenues associated with changes in rates and pricing increased in the first quarter 2014 when compared to the corresponding period in 2013 primarily due to a PEP base rate increase effective on March 19, 2013, a rate increase related to Kemper IGCC cost recovery 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 in the first quarter 2014 when compared to the corresponding period in 2013. KWH energy sales to industrial customers increased 3.1% due to increased usage by larger customers. Weather-adjusted KWH energy sales to residential customers increased 1.0% when compared to the corresponding period in 2013 due to an increase in the number of residential customers. Weather-adjusted KWH energy sales to commercial customers increased 3.0% when compared to the corresponding period in 2013 due to improving commercial economic activity.

Fuel and other cost recovery revenues increased in the first quarter 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.

Wholesale Revenues – Non-Affiliates

First Quarter 2014 vs. First Quarter 2013
(change in millions)	(% change)
$31.6	48.5

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 first quarter 2014, wholesale revenues from sales to non-affiliates were $96.7 million compared to $65.1 million for the corresponding period in 2013. The increase was due to a $14.1 million increase in base revenues primarily resulting from a wholesale base rate increase effective April 1, 2013 and a $17.5 million increase in energy revenues, of which $9.2 million was primarily associated with higher fuel prices and $8.3 million was associated with an increase in KWH sales due to higher demand resulting from colder weather in the first quarter 2014 compared to the corresponding period in 2013.

Wholesale Revenues – Affiliates

First Quarter 2014 vs. First Quarter 2013
(change in millions)	(% change)
$14.5	173.2

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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 first quarter 2014, wholesale revenues from sales to affiliates were $22.8 million compared to $8.3 million for the corresponding period in 2013. The increase was primarily due to a $14.5 million increase in energy revenues, of which $9.3 million was associated with an increase in KWH sales and $5.2 million was associated with higher prices.

Fuel and Purchased Power Expenses

	First Quarter 2014 vs. First Quarter 2013
	(change in millions)			(% change)
Fuel	$	42.4		40.5
Purchased power – non-affiliates	10.1			N/M
Purchased power – affiliates	(0.8		)	(7.8)
Total fuel and purchased power expenses	$	51.7

N/M - Not meaningful

In the first quarter 2014, total fuel and purchased power expenses were $167.3 million compared to $115.6 million for the corresponding period in 2013. The increase was primarily due to a $41.5 million increase in the total volume of KWHs generated and purchased and a $10.2 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:

	First Quarter 2014	First Quarter 2013
Total generation (millions of KWHs)	4,043	3,204
Total purchased power (millions of KWHs)	258	393
Sources of generation (percent) –
Coal	46	27
Gas	54	73
Cost of fuel, generated (cents per net KWH) –
Coal	4.23	5.03
Gas	3.59	2.98
Average cost of fuel, generated (cents per net KWH)	3.91	3.57
Average cost of purchased power (cents per net KWH)(a)	7.90	2.82

(a) Includes test period energy for the Kemper IGCC of $6.4 million in the first quarter 2014. Excluding these costs, the average cost of purchased power was 5.44 cents per net KWH.

Fuel

In the first quarter 2014, fuel expense was $147.0 million compared to $104.6 million for the corresponding period in 2013. The increase was primarily due to a 28.4% 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 9.5%

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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 first quarter 2014, purchased power expense from non-affiliates was $11.4 million compared to $1.3 million for the corresponding period in 2013. The increase was primarily the result of a 565.3% increase in the average cost per KWH purchased and a 26.4% increase in the volume of KWHs purchased. The increase in the average cost per KWH purchased includes $6.4 million of test period energy for the Kemper IGCC. Excluding these costs, the average cost per KWH purchased increased 197.0%.

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

Purchased Power - Affiliates

In the first quarter 2014, purchased power expense from affiliates was $8.9 million compared to $9.7 million for the corresponding period in 2013. The decrease was primarily due to a 48.9% decrease in the volume of KWHs purchased, partially offset by an 80.3% increase in the average cost per KWH 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

First Quarter 2014 vs. First Quarter 2013
(change in millions)	(% change)
$11.3	20.6

In the first quarter 2014, other operations and maintenance expenses were $66.1 million compared to $54.8 million for the corresponding period in 2013. The increase was primarily due to an $11.3 million increase in generation maintenance expenses primarily related to scheduled outages.

Estimated Loss on Kemper IGCC

First Quarter 2014 vs. First Quarter 2013
(change in millions)	(% change)
$(82.0)	(17.7)

In the first quarters of 2014 and 2013, estimated probable losses on the Kemper IGCC of $380.0 million and $462.0 million, respectively, were recorded to reflect revisions of estimated costs expected to be incurred on the construction of the Kemper IGCC in excess of the $2.88 billion cost cap established by the Mississippi PSC, net of the DOE Grants and excluding the Cost Cap Exceptions.

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.

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Allowance for Equity Funds Used During Construction

First Quarter 2014 vs. First Quarter 2013
(change in millions)	(% change)
$12.0	46.1

In the first quarter 2014, AFUDC equity was $38.1 million compared to $26.1 million for the corresponding period in 2013. The increase was 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

First Quarter 2014 vs. First Quarter 2013
(change in millions)	(% change)
$1.6	15.6

In the first quarter 2014, interest expense, net of amounts capitalized was $12.0 million compared to $10.4 million for the corresponding period in 2013. The increase was primarily due to a $1.1 million increase in interest expense associated with issuances of new long-term debt, a $2.4 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, and a $1.3 million increase in interest expense on the regulatory liability related to the Kemper IGCC rate recovery. 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 $0.8 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)

First Quarter 2014 vs. First Quarter 2013
(change in millions)	(% change)
$39.5	23.4

In the first quarter 2014, income taxes (benefit) were $(129.6) million compared to $(169.1) million for the corresponding period in 2013. The change was primarily due to a lower pre-tax loss 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 operation of ongoing construction projects, primarily the Kemper IGCC. Future earnings in the near term will depend, in part, upon maintaining energy sales which is subject to a number of factors. These factors include weather, competition, new

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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 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). 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. Pending such further proceedings, it is anticipated that CSAPR will remain stayed and the EPA will continue to administer the Clean Air Interstate Rule. The ultimate outcome of this matter 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 Mississippi Power in Item 7 of the Form 10-K for additional information regarding the EPA's proposed rule for cooling water intake structures.

On April 16, 2014, the EPA requested an extension of its deadline for issuing a final rule for cooling water intake structures until May 16, 2014.

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.

FERC Matters

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters" and "Integrated Coal Gasification Combined Cycle" of Mississippi Power in Item 7 and Note 3 to the

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

On March 31, 2014, Mississippi Power reached a settlement agreement with its wholesale customers and filed a request with the FERC for an additional increase in the Municipal and Rural Associations (MRA) cost-based electric tariff. The settlement agreement, if approved by the FERC, 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. If the settlement agreement is approved by the FERC, the amount of base rate revenues to be received in 2014 from the agreed upon increase is expected to be approximately $6.9 million. The ultimate outcome of this matter cannot be determined at this time.

PSC Matters

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.

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. The ultimate outcome of this matter 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 "Fuel Cost Recovery" herein for additional information.

At March 31, 2014, the amount of under recovered retail fuel costs included on Mississippi Power's Condensed Balance Sheet herein was $1.8 million compared to over recovered retail fuel costs of $14.5 million at December 31, 2013.

Ad Valorem Tax Adjustment

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, primarily due to an increase in property tax rates.

See MANAGEMENT'S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS – "Taxes Other Than Income Taxes" of Mississippi Power in Item 7 of the Form 10-K for additional information.

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

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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. The ultimate outcome of the CPCN challenge 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 Settlement Agreement (described 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. However, as a result of the construction issues identified in March 2014, as well as the risk of additional factors that have the potential to further extend construction and start-up as described below, the in-service date for the remainder of the Kemper IGCC, including the gasification system, is currently expected to occur in the first half of 2015.

Mississippi Power's 2010 project estimate, current cost estimate, and actual costs incurred as of March 31, 2014 for the Kemper IGCC are as follows:

Cost Category	2010 Project Estimate(e)		Current Estimate		Actual Costs at March 31, 2014
	(in billions)
Plant Subject to Cost Cap(a)	$	2.40	$	4.44	$	3.52
Lignite Mine and Equipment	0.21		0.23		0.23
CO2 Pipeline Facilities	0.14		0.11		0.10
AFUDC(b)(c)	0.17		0.55		0.32
General Exceptions	0.05		0.10		0.07
Regulatory Asset(c)(d)	—		0.10		0.08
Total Kemper IGCC(a)(c)	$	2.97	$	5.53	$	4.32

(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 March 31, 2014, $2.67 billion was included in CWIP (which is net of the DOE Grants and estimated probable losses of $1.56 billion), $83.9 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

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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. These amounts are 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 estimated to result in additional costs of approximately $25 million per month.

Any further cost increases and/or extensions of the in-service date with respect to the Kemper IGCC may result from factors including, but not limited to, labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under construction or other agreements, operational performance, and/or start-up activities for this "first-of-a-kind" technology, including major equipment failure, system integration, and operations, and/or unforeseen engineering problems. 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 and/or any amount in excess of the $1.0 billion securitization limit (described below) will be reflected in 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 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.

Settlement Agreement

In January 2013, Mississippi Power entered into the 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. Under the 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 Settlement Agreement also allows Mississippi Power to secure alternate financing for costs that are not otherwise

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recovered in any Mississippi PSC rate proceedings contemplated by the 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 Settlement Agreement provides that Mississippi Power may terminate the 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 Settlement Agreement, or if the Mississippi PSC fails to comply with the requirements of the Settlement Agreement. Mississippi Power continues to work with the Mississippi PSC and the Mississippi Public Utilities Staff to implement the requirements of the Settlement Agreement.

2013 MPSC Rate Order

Consistent with the terms of the 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, to be recorded to a regulatory liability to be used to mitigate rate impacts when the Kemper IGCC is placed in service.

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. Amounts collected through these rates are being recorded as a regulatory liability to be used to mitigate customer rate impacts after the Kemper IGCC is placed in service. As of March 31, 2014, $135.5 million had been collected, with $4.4 million recognized in retail rate revenues in the first quarter 2014 in Mississippi Power's Condensed Statements of Income herein and the remainder deferred in other regulatory liabilities 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

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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 $120 million to $150 million. See "Income Tax Matters – Bonus Depreciation" herein for additional information regarding bonus depreciation.

In 2014, 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 approximately $45 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 prudence review of Kemper IGCC costs incurred through March 31, 2013, as provided for in the Settlement Agreement, is ongoing, with hearings currently expected to occur in the third quarter 2014. A final review of all costs incurred after March 31, 2013 is expected to be completed within six months of the Kemper IGCC's in-service date. Furthermore, regardless of any prudence determinations made during the construction and start-up period, the Mississippi PSC has the right to make a final prudence determination after the Kemper IGCC has been placed in service. The Mississippi PSC through its scheduling orders 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.

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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 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

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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 $170 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 March 31, 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.

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.

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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

Mississippi Power has extended the scheduled in-service date for the Kemper IGCC to the first half of 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 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, in addition to charges totaling $1.18 billion ($728.7 million after tax) recognized through December 31, 2013. 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 and/or any amount in excess of the $1.0 billion securitization limit 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, and/or start-up activities for this "first-of-a-kind" technology, including major equipment failure, system integration, and operations, and/or unforeseen engineering problems.

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.

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 three months ended March 31, 2014 were negatively affected by revisions to the cost estimate for the Kemper IGCC, Mississippi Power's financial condition remained stable at March 31, 2014. Through March 31, 2014, Mississippi Power has incurred non-recoverable cash expenditures of $636.1 million and is expected to incur approximately $924 million in additional non-recoverable cash expenditures through completion of the Kemper IGCC. Subsequent to March 31, 2014, Mississippi Power received $60 million in equity contributions from Southern Company.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 $32.2 million for the first three months of 2014, an increase of $57.4 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, an increase in accounts payable, and a decrease in fossil fuel stock, partially offset by an increase in prepaid income taxes and a decrease in over-recovered regulatory clause revenue. Net cash used for investing activities totaled $361.4 million for the first three months of 2014 primarily due to gross property additions related to the Kemper IGCC and the Plant Daniel scrubber. Net cash provided from financing activities totaled $269.2 million for the first three months of 2014 primarily due to 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 year to year based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes for the first three months of 2014 include a decrease in total property, plant, and equipment of $40.4 million, a net increase in accumulated deferred income taxes of $107.3 million, and a decrease in common stockholder's equity of $225.3 million primarily due to the Kemper IGCC. Fossil fuel stock decreased $36.6 million primarily due to decreased coal inventories and other accrued taxes decreased $51.9 million primarily due to payment of ad valorem taxes. Securities due within one year increased $300.0 million due to bank loans maturing in March 2015 and long-term debt decreased $52.9 million due to the reclassification of bank loans, partially offset by an additional $250.0 million bank loan. 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, 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 $313.8 million will be required through March 31, 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 years 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 Cost Estimate" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle – Kemper IGCC Cost Estimate" herein for additional information and further risks related to the estimated schedule and costs and rate recovery for the Kemper IGCC.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Sources of Capital

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.

In 2011, Mississippi Power 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. 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 March 31, 2014, Mississippi Power had approximately $85.2 million of cash and cash equivalents. Committed credit arrangements with banks at March 31, 2014 were as follows:

Expires(a)								Executable Term Loans				Due Within One Year
2014		2016		Total		Unused		One Year		Two Years		Term Out		No Term Out
(in millions)				(in millions)				(in millions)				(in millions)
$	135	$	165	$	300	$	300	$	25	$	40	$	65	$	70

(a) No credit arrangements expire in 2015, 2017, or 2018.

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 March 31, 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 period ended March 31, 2014.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Management believes that the need for working capital can be adequately met by utilizing commercial paper, equity contributions or loans from Southern Company, lines of credit, 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, emissions allowances, and energy price risk management. At March 31, 2014, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $236 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 in 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 10.111% per annum for the period ended March 31, 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 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 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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SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended March 31,
	2014			2013
	(in thousands)
Operating Revenues:
Wholesale revenues, non-affiliates	$	277,868		$	223,429
Wholesale revenues, affiliates	72,333			78,191
Other revenues	653			1,327
Total operating revenues	350,854			302,947
Operating Expenses:
Fuel	124,562			119,372
Purchased power, non-affiliates	27,893			14,573
Purchased power, affiliates	29,186			7,865
Other operations and maintenance	52,715			50,950
Depreciation and amortization	51,457			40,160
Taxes other than income taxes	5,683			5,354
Total operating expenses	291,496			238,274
Operating Income	59,358			64,673
Other Income and (Expense):
Interest expense, net of amounts capitalized	(22,003		)	(20,394		)
Other income (expense), net	118			(257		)
Total other income and (expense)	(21,885		)	(20,651		)
Earnings Before Income Taxes	37,473			44,022
Income taxes	3,186			14,830
Net Income	34,287			29,192
Less: Net income attributable to noncontrolling interest	816			—
Net Income Attributable to Southern Power Company	$	33,471		$	29,192

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended March 31,
	2014			2013
	(in thousands)
Net Income	$	34,287		$	29,192
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 $39 and $1,045, respectively	89			1,634
Total other comprehensive income (loss)	87			1,634
Less: Comprehensive income attributable to noncontrolling interest	816			—
Comprehensive Income Attributable to Southern Power Company	$	33,558		$	30,826

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 Three Months Ended March 31,
	2014			2013
	(in thousands)
Operating Activities:
Net income	$	34,287		$	29,192
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	50,264			42,790
Deferred income taxes	(14,087		)	13,587
Investment tax credits	26,134			(493		)
Deferred revenues	(20,033		)	(20,432		)
Other, net	2,184			233
Changes in certain current assets and liabilities —
-Receivables	21,034			11,743
-Fossil fuel stock	2,487			1,840
-Materials and supplies	(2,763		)	(1,546		)
-Prepaid income taxes	14,911			1,600
-Other current assets	2,129			1,324
-Accounts payable	2,232			(6,933		)
-Accrued taxes	5,831			4,155
-Accrued interest	(14,502		)	(10,841		)
-Other current liabilities	(42		)	(314		)
Net cash provided from operating activities	110,066			65,905
Investing Activities:
Property additions	(5,468		)	(58,553		)
Change in construction payables	543			3,704
Payments pursuant to long-term service agreements	(10,029		)	(11,741		)
Other investing activities	54			(224		)
Net cash used for investing activities	(14,900		)	(66,814		)
Financing Activities:
Increase in notes payable, net	—			76,985
Proceeds —
Capital contributions	(2,752		)	1,033
Other long-term debt	639			1,717
Repayments — Other long-term debt	(818		)	(220		)
Distributions to noncontrolling interest	(150		)	—
Contributions from noncontrolling interest	471			—
Payment of common stock dividends	(32,780		)	(32,280		)
Other financing activities	631			678
Net cash provided from (used for) financing activities	(34,759		)	47,913
Net Change in Cash and Cash Equivalents	60,407			47,004
Cash and Cash Equivalents at Beginning of Period	68,744			28,592
Cash and Cash Equivalents at End of Period	$	129,151		$	75,596
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $(113) and $- capitalized for 2014 and 2013, respectively)	$	35,790		$	28,120
Income taxes, net	(44,468		)	(179		)
Noncash transactions — accrued property additions at end of period	4,810			8,907

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 March 31, 2014		At December 31, 2013
	(in thousands)
Current Assets:
Cash and cash equivalents	$	129,151	$	68,744
Receivables —
Customer accounts receivable	69,757		73,497
Other accounts receivable	3,901		3,983
Affiliated companies	21,343		38,391
Fossil fuel stock, at average cost	16,920		19,178
Materials and supplies, at average cost	57,542		54,780
Prepaid service agreements—current	65,321		81,206
Prepaid income taxes	24,237		54,732
Other prepaid expenses	5,715		7,915
Assets from risk management activities	231		182
Total current assets	394,118		402,608
Property, Plant, and Equipment:
In service	4,705,764		4,696,134
Less accumulated provision for depreciation	928,641		871,963
Plant in service, net of depreciation	3,777,123		3,824,171
Construction work in progress	10,926		9,843
Total property, plant, and equipment	3,788,049		3,834,014
Other Property and Investments:
Goodwill	1,839		1,839
Other intangible assets, net of amortization of $6,232 and $5,614 at March 31, 2014 and December 31, 2013, respectively	42,887		43,505
Total other property and investments	44,726		45,344
Deferred Charges and Other Assets:
Prepaid long-term service agreements	96,550		73,676
Other deferred charges and assets — affiliated	7,813		4,605
Other deferred charges and assets — non-affiliated	72,564		68,853
Total deferred charges and other assets	176,927		147,134
Total Assets	$	4,403,820	$	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 March 31, 2014		At December 31, 2013
	(in thousands)
Current Liabilities:
Securities due within one year	$	1,412	$	599
Accounts payable —
Affiliated	61,270		56,661
Other	20,469		20,747
Accrued taxes —
Accrued income taxes	2,304		161
Other accrued taxes	6,350		2,662
Accrued interest	13,850		28,352
Deferred capacity revenues — current affiliated	1,536		4,229
Other current liabilities	12,863		14,263
Total current liabilities	120,054		127,674
Long-term Debt	1,618,263		1,619,241
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	717,033		724,390
Accumulated deferred investment tax credits	341,702		340,269
Deferred capacity revenues — affiliated	5,297		15,279
Other deferred credits and liabilities — affiliated	1,367		1,621
Other deferred credits and liabilities — non-affiliated	8,211		7,896
Total deferred credits and other liabilities	1,073,610		1,089,455
Total Liabilities	2,811,927		2,836,370
Redeemable Noncontrolling Interest	29,914		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	1,026,283		1,029,035
Retained earnings	532,690		531,998
Accumulated other comprehensive income	3,006		2,919
Total common stockholder's equity	1,561,979		1,563,952
Total Liabilities and Stockholder's Equity	$	4,403,820	$	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

FIRST QUARTER 2014 vs. FIRST QUARTER 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 capacity contracts 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 is expected to begin commercial operation in May 2014 and serves a PPA with Southern California Edison Company (SCE) covering the entire output of the plant from the commercial operation date 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 (the lower the better). 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

First Quarter 2014 vs. First Quarter 2013
(change in millions)	(% change)
$4.3	14.7

Net income attributable to Southern Power for the first quarter 2014 was $33.5 million compared to $29.2 million for the corresponding period in 2013. The increase was primarily due to an increase in energy revenues from non-affiliates and a decrease in income taxes, partially offset by an increase in depreciation.

Wholesale Revenues–Non-Affiliates

First Quarter 2014 vs. First Quarter 2013
(change in millions)	(% change)
$54.5	24.4

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 first quarter 2014 were $277.9 million compared to $223.4 million for the corresponding period in 2013. The increase was primarily due to a $54.8 million increase in energy sales, primarily as a result of increased revenue under existing contracts, reflecting a 45.1% increase in the average price

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

of energy, primarily as a result of higher natural gas prices. Also contributing to this increase is revenue from new solar PPAs and requirements contracts.

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

First Quarter 2014 vs. First Quarter 2013
(change in millions)	(% change)
$(5.9)	(7.5)

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

Wholesale revenues from affiliates for the first quarter 2014 were $72.3 million compared to $78.2 million for the corresponding period in 2013. The decrease was the result of a $9.6 million decrease in energy sales under the IIC, reflecting a 46.1% 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 $3.7 million increase in energy sales under existing PPAs, 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.

Fuel and Purchased Power Expenses

	First Quarter 2014 vs. First Quarter 2013
	(change in millions)		(% change)
Fuel	$	5.2	4.3
Purchased power – non-affiliates	13.4		91.4
Purchased power – affiliates	21.3		271.1
Total fuel and purchased power expenses	$	39.9

Southern Power PPAs 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 first quarter 2014, total fuel and purchased power expenses were $181.7 million compared to $141.8 million for the corresponding period in 2013. Fuel and purchased power expenses increased $64.3 million primarily due to a 52.7% increase in the average cost of natural gas and a 62.4% increase in the average cost of purchased power. The increase was partially offset by a $24.4 million decrease associated with a 21.2% net decrease in the volume of KWHs generated and purchased primarily as a result of higher natural gas prices and the availability of lower cost affiliate power.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

In the first quarter 2014, fuel expense was $124.6 million compared to $119.4 million for the corresponding period in 2013. The increase was primarily due to a $42.3 million increase associated with the average cost of natural gas per KWH generated, partially offset by a $37.1 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 first quarter 2014, purchased power expense was $57.1 million compared to $22.4 million for the corresponding period in 2013. The increase was due to a $22.0 million increase associated with the cost of purchased power and a $12.7 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.

Depreciation and Amortization

First Quarter 2014 vs. First Quarter 2013
(change in millions)	(% change)
$11.3	28.1

In the first quarter 2014, depreciation and amortization was $51.5 million compared to $40.2 million for the corresponding period in 2013. The increase was primarily due to an increase in depreciation expense related to Plants Campo Verde and Spectrum placed in service in 2013 and accelerated outage work.

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

Income Taxes

First Quarter 2014 vs. First Quarter 2013
(change in millions)	(% change)
$(11.6)	(78.5)

In the first quarter 2014, income taxes were $3.2 million compared to $14.8 million for the corresponding period in 2013. The decrease resulted from an increase in state income tax credits and beneficial changes in certain state income tax laws that increased tax benefits by $8.6 million compared to the prior period as well as lower pre-tax income.

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 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, or other environmental and health concerns could also

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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). 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. Pending such further proceedings, it is anticipated that CSAPR will remain stayed and the EPA will continue to administer the Clean Air Interstate Rule. The ultimate outcome of this matter 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 proposed rule for cooling water intake structures.

On April 16, 2014, the EPA requested an extension of its deadline for issuing a final rule for cooling water intake structures until May 16, 2014.

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 is expected to begin commercial operation in May 2014. The output of the plant is contracted under a 20-year PPA with SCE, which will begin on the commercial operation date.

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.

On April 17, 2014, a subsidiary of Southern Power assumed a PPA with SCE in connection with the acquisition of Adobe. Commercial operation is expected to begin in May 2014. See Note (I) to the Condensed Financial Statements herein for additional information.

Other Matters

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

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SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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.

FINANCIAL CONDITION AND LIQUIDITY

Overview

Southern Power's financial condition remained stable at March 31, 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 $110.1 million for the first three months of 2014, an increase of $44.2 million as compared to the first three 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 a reduction in receivables from affiliated companies. Net cash used for investing activities totaled $14.9 million for the first three months of 2014 primarily due to expenditures related to payments pursuant to long-term service agreements and capital additions related to outage work. Net cash used for financing activities totaled $34.8 million for the first three months of 2014 primarily due to the payment of common stock dividends. Fluctuations in cash flow from financing activities vary year to year based on capital needs and the maturity or redemption of securities.

Significant asset changes in the balance sheet for the first three months of 2014 include a $30.5 million decrease in prepaid income taxes primarily as a result of less ITCs utilized.

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 March 31, 2015.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 frequently 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 March 31, 2014 cash and cash equivalents of approximately $129.2 million and Southern Power Company had a committed credit facility of $500 million (Facility) expiring in 2018.

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'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.

Southern Power had no commercial paper or short-term debt outstanding during the period ended March 31, 2014.

Management believes that the need for working capital can be adequately met by utilizing the commercial paper program, the Facility, 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.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The maximum potential collateral requirements under these contracts at March 31, 2014 were as follows:

Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB and Baa2	$	9
At BBB- and/or Baa3	316
Below BBB- and/or Baa3	1,018

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

In March 2014, Southern Power prepaid $0.8 million of long-term debt to TRE.

In March 2014, Southern Power issued an additional $0.6 million under a promissory note, due April 20, 2033, to TRE related to the financing of Campo Verde Solar, LLC.

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.

115

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	117
B	Contingencies and Regulatory Matters	117
C	Fair Value Measurements	131
D	Stockholders' Equity	136
E	Financing	137
F	Retirement Benefits	139
G	Effective Tax Rate	141
H	Derivatives	141
I	Acquisitions	148
J	Segment and Related Information	148

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

116

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)

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 March 31, 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 filings 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 quarter 2014 and is not expected to have a material impact on the financial statements of Southern Company or Southern Power in future periods.

(B) CONTINGENCIES AND REGULATORY MATTERS

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

General Litigation Matters

Each registrant is subject to certain claims and legal actions arising in the ordinary course of business. In addition, business activities of Southern Company's subsidiaries are subject to extensive governmental regulation related to public health and the environment, such as regulation of air emissions and water discharges. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law

117

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

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 March 31, 2014 was $18 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.

118

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

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 March 31, 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, the Texas Commission on Environmental Quality (TCEQ) designated Mississippi Power as a PRP at a site in Texas. The site was owned by an electric transformer company that handled Mississippi Power's transformers as well as those of many other entities. 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. The remediation expenses incurred by Mississippi Power are expected to be recovered through the ECO Plan and are not expected to have a material impact on Southern Company's or Mississippi Power's financial statements.

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

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(UNAUDITED)

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. No amounts have been recognized in the financial statements as of March 31, 2014 for any potential recoveries from these lawsuits. The final outcome of these matters cannot be determined at this time; however, no material impact on Southern Company's, Alabama Power's, or Georgia Power's net income is expected.

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 Mississippi Power's settlement agreement with its wholesale customers for revised rates related to the wholesale Municipal and Rural Associations (MRA) cost-based electric tariff. 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 additional increase in the MRA cost-based electric tariff. The settlement agreement, if approved by the FERC, 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. If the settlement agreement is approved by the FERC, the amount of base rate revenues to be received in 2014 from the agreed upon increase is expected to be approximately $6.9 million. The ultimate outcome of this matter cannot be determined at this time.

Retail Regulatory Matters

Alabama Power

See Note 3 to the financial statements of Southern Company and Alabama Power under "Retail Regulatory Matters – Alabama Power" and "Retail Regulatory Matters," respectively, in Item 8 of the Form 10-K for additional information regarding Alabama Power's recovery of retail costs through various regulatory clauses and accounting orders. The recovery balance of each regulatory clause follows:

Regulatory Clause	Balance Sheet Line Item	March 31, 2014		December 31, 2013
		(in millions)
Rate CNP Environmental – Under	Deferred under recovered regulatory clause revenues	$	13	$	7
Rate CNP PPA – Under	Deferred under recovered regulatory clause revenues	23		18
Retail Energy Cost Recovery – Over	Other regulatory liabilities, current	22		27
	Deferred over recovered regulatory clause revenues	—		15
Natural Disaster Reserve	Other regulatory liabilities, deferred	91		96

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(UNAUDITED)

Georgia Power

Fuel Cost Recovery

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

As of March 31, 2014, Georgia Power's under recovered fuel balance totaled $157 million and is included in current assets and other deferred charges and assets on Southern Company's and Georgia Power's Condensed Balance Sheets herein. As of December 31, 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 in the financial statements are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, any 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

Georgia Power defers and recovers certain costs related to damages from major storms as mandated by the Georgia PSC. As of March 31, 2014 and December 31, 2013, the balance in the regulatory asset related to storm damage was $110 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

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(UNAUDITED)

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 an 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 March 31, 2014, approximately $32 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 commercial operation date 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 expects to resume filing semi-annual VCM reports in 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. The portion of additional costs claimed by the Contractor 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. 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. 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. While litigation has commenced 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.

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(UNAUDITED)

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 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 ROE range then in effect. In the first quarter 2014, Gulf Power recognized a reduction in depreciation expense of $6.2 million.

Cost Recovery Clauses

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

Recovery Clause	Balance Sheet Location	March 31, 2014		December 31, 2013
		(in millions)
Fuel Cost Recovery – Under	Under recovered regulatory clause revenues	$	35.7	$	21.0
Purchased Power Capacity Recovery – Over	Other regulatory liabilities, current	5.5		—
Purchased Power Capacity Recovery – Under	Under recovered regulatory clause revenues	—		2.8
Environmental Cost Recovery – Under	Under recovered regulatory clause revenues	17.1		14.4
Energy Conservation Cost Recovery – Under	Under recovered regulatory clause revenues	6.3		7.0

Mississippi Power

Performance Evaluation Plan

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

On March 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.

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(UNAUDITED)

The ultimate outcome of this matter 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. Also in 2012, the Sierra Club filed a notice of appeal of the order with the Chancery Court. 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 March 31, 2014, total project expenditures were $370.2 million, of which Mississippi Power's portion was $188.1 million, excluding AFUDC of $10.7 million.

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

Fuel Cost Recovery

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

At March 31, 2014, the amount of under recovered retail fuel costs included on Mississippi Power's Condensed Balance Sheet herein was $1.8 million compared to over recovered retail fuel costs of $14.5 million at December 31, 2013.

Ad Valorem Tax Adjustment

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, 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. The ultimate outcome of the CPCN challenge 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 Settlement Agreement (described 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. However, as a result of the construction issues identified in March 2014, as well as the risk of additional factors that have the potential to further extend construction and start-up as described below, the in-service date for the remainder of the Kemper IGCC, including the gasification system, is currently expected to occur in the first half of 2015.

Mississippi Power's 2010 project estimate, current cost estimate, and actual costs incurred as of March 31, 2014 for the Kemper IGCC are as follows:

Cost Category	2010 Project Estimate(e)		Current Estimate		Actual Costs at March 31, 2014
	(in billions)
Plant Subject to Cost Cap(a)	$	2.40	$	4.44	$	3.52
Lignite Mine and Equipment	0.21		0.23		0.23
CO2 Pipeline Facilities	0.14		0.11		0.10
AFUDC(b)(c)	0.17		0.55		0.32
General Exceptions	0.05		0.10		0.07
Regulatory Asset(c)(d)	—		0.10		0.08
Total Kemper IGCC(a)(c)	$	2.97	$	5.53	$	4.32

(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 March 31, 2014, $2.67 billion was included in CWIP (which is net of the DOE Grants and estimated probable losses of $1.56 billion), $83.9 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. These amounts are 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 estimated to result in additional costs of approximately $25 million per month.

Any further cost increases and/or extensions of the in-service date with respect to the Kemper IGCC may result from factors including, but not limited to, labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under construction or other agreements, operational performance, and/or start-up activities for this "first-of-a-kind" technology, including major equipment failure, system integration, and operations, and/or unforeseen engineering problems. 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 and/or any amount in excess of the $1.0 billion securitization limit (described below) 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.

Settlement Agreement

In January 2013, Mississippi Power entered into the 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. Under the 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

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(UNAUDITED)

other costs permitted or determined to be excluded from the $2.88 billion cost cap by the Mississippi PSC. The 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 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 Settlement Agreement provides that Mississippi Power may terminate the 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 Settlement Agreement, or if the Mississippi PSC fails to comply with the requirements of the Settlement Agreement. Mississippi Power continues to work with the Mississippi PSC and the Mississippi Public Utilities Staff to implement the requirements of the Settlement Agreement.

2013 MPSC Rate Order

Consistent with the terms of the 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, to be recorded to a regulatory liability to be used to mitigate rate impacts when the Kemper IGCC is placed in service.

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. Amounts collected through these rates are being recorded as a regulatory liability to be used to mitigate customer rate impacts after the Kemper IGCC is placed in service. As of March 31, 2014, $135.5 million had been collected, with $4.4 million recognized in retail rate revenues in the first quarter 2014 in Southern Company's and Mississippi Power's Condensed Statements of Income herein and the remainder deferred in other regulatory liabilities 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.

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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 $120 million to $150 million. See "Investment Tax Credits and Bonus Depreciation" herein for additional information regarding bonus depreciation.

In 2014, 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 approximately $45 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 prudence review of Kemper IGCC costs incurred through March 31, 2013, as provided for in the Settlement Agreement, is ongoing, with hearings currently expected to occur in the third quarter 2014. A final review of all costs incurred after March 31, 2013 is expected to be completed within six months of the Kemper IGCC's in-service date. Furthermore, regardless of any prudence determinations made during the construction and start-up period, the Mississippi PSC has the right to make a final prudence determination after the Kemper IGCC has been placed in service. The Mississippi PSC through its scheduling orders 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.

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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

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(UNAUDITED)

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 March 31, 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 $170 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.

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(UNAUDITED)

(C) FAIR VALUE MEASUREMENTS

As of March 31, 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 March 31, 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
Interest rate derivatives	3		—		—		3
Nuclear decommissioning trusts(a)	626		884		2		1,512
Cash equivalents	408		—		—		408
Other investments	9		—		4		13
Total	$	1,046	$	924	$	6	$	1,976
Liabilities:
Energy-related derivatives	$	—	$	43	$	—	$	43
Alabama Power
Assets:
Energy-related derivatives	$	—	$	12	$	—	$	12
Nuclear decommissioning trusts(b)
Domestic equity	403		77		—		480
Foreign equity	35		65		—		100
U.S. Treasury and government agency securities	—		29		—		29
Corporate bonds	—		88		—		88
Mortgage and asset backed securities	—		18		—		18
Other	—		9		2		11
Cash equivalents	176		—		—		176
Total	$	614	$	298	$	2	$	914
Liabilities:
Energy-related derivatives	$	—	$	6	$	—	$	6

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(UNAUDITED)

	Fair Value Measurements Using
As of March 31, 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	$	—	$	8	$	—	$	8
Nuclear decommissioning trusts(b) (c)
Domestic equity	188		1		—		189
Foreign equity	—		131		—		131
U.S. Treasury and government agency securities	—		125		—		125
Municipal bonds	—		40		—		40
Corporate bonds	—		153		—		153
Mortgage and asset backed securities	—		103		—		103
Other	—		45		—		45
Total	$	188	$	606	$	—	$	794
Liabilities:
Energy-related derivatives	$	—	$	16	$	—	$	16
Gulf Power
Assets:
Energy-related derivatives	$	—	$	12	$	—	$	12
Cash equivalents	18		—		—		18
Total	$	18	$	12	$	—	$	30
Liabilities:
Energy-related derivatives	$	—	$	13	$	—	$	13
Mississippi Power
Assets:
Energy-related derivatives	$	—	$	8	$	—	$	8
Cash equivalents	63		—		—		63
Total	$	63	$	8	$	—	$	71
Liabilities:
Energy-related derivatives	$	—	$	8	$	—	$	8
Southern Power
Assets:
Cash equivalents	$	115	$	—	$	—	$	115

(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 March 31, 2014, approximately $51 million of the fair market value of Georgia Power's nuclear decommissioning trust funds' securities were on loan and pledged to creditors under the funds' managers' securities lending program.

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(UNAUDITED)

Valuation Methodologies

The energy-related derivatives primarily consist of over-the-counter financial products for natural gas and physical power products including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and overnight index swap interest rates. Interest rate 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.

"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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(UNAUDITED)

As of March 31, 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 March 31, 2014:	Fair Value		Unfunded Commitments	Redemption Frequency	Redemption Notice Period
	(in millions)
Southern Company
Nuclear decommissioning trusts:
Foreign equity funds	$	131	None	Monthly	5 days
Equity - commingled funds	65		None	Daily/Monthly	Daily/7 days
Other - commingled funds	45		None	Daily/Monthly	Daily/7 days
Trust-owned life insurance	111		None	Daily	15 days
Cash equivalents:
Money market funds	408		None	Daily	Not applicable
Alabama Power
Nuclear decommissioning trusts:
Equity - commingled funds	$	65	None	Daily/Monthly	Daily/7 days
Trust-owned life insurance	111		None	Daily	15 days
Cash equivalents:
Money market funds	176		None	Daily	Not applicable
Georgia Power
Nuclear decommissioning trusts:
Foreign equity funds	$	131	None	Monthly	5 days
Other - commingled funds	45		None	Daily	Not applicable
Gulf Power
Cash equivalents:
Money market funds	$	18	None	Daily	Not applicable
Mississippi Power
Cash equivalents:
Money market funds	$	63	None	Daily	Not applicable
Southern Power
Cash equivalents:
Money market funds	$	115	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 March 31, 2014 is $7 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. 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 months ended March 31, 2014, the change in fair value of the funds, including reinvested interest and dividends reduced by the funds' expenses, increased by $27 million at Southern Company. Alabama Power recorded an increase in fair value of $16 million as an increase in regulatory liabilities. Georgia Power recorded an increase in fair value of $11 million 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.

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(UNAUDITED)

As of March 31, 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	$	22,896	$	23,963
Alabama Power	$	6,228	$	6,689
Georgia Power	$	9,593	$	9,997
Gulf Power	$	1,233	$	1,308
Mississippi Power	$	2,346	$	2,346
Southern Power	$	1,620	$	1,709

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 March 31, 2014	Three Months Ended March 31, 2013
	(in millions)
As reported shares	890	870
Effect of options and performance share award units	3	5
Diluted shares	893	875

Stock options and performance share award units that were not included in the diluted earnings per share calculation because they were anti-dilutive were 17 million for the three months ended March 31, 2014 and were immaterial for the three months ended March 31, 2013.

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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	—	—		351			—		351
Other comprehensive income (loss)	—	—		2			—		2
Treasury stock re-issued	—	2,404		111			—		111
Stock issued	1,340	—		53			—		53
Stock repurchased, at cost	—	—		(4		)	—		(4		)
Cash dividends on common stock	—	—		(451		)	—		(451		)
Other	—	(18	)	—			—		—
Balance at March 31, 2014	894,073	(3,261	)	$	19,070		$	756	$	19,826
Balance at December 31, 2012	877,803	(10,035	)	$	18,297		$	707	$	19,004
Net income after dividends on preferred and preference stock	—	—		81			—		81
Other comprehensive income (loss)	—	—		4			—		4
Stock issued	2,638	—		99			—		99
Stock repurchased, at cost	—	—		(18		)	—		(18		)
Cash dividends on common stock	—	—		(426		)	—		(426		)
Other	—	(15	)	—			—		—
Balance at March 31, 2013	880,441	(10,050	)	$	18,037		$	707	$	18,744

(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 March 31, 2014 was approximately $1.8 billion. In addition, at March 31, 2014, the traditional operating companies had $559 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.

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(UNAUDITED)

The following table outlines the committed credit arrangements by company as of March 31, 2014:

	Expires(a)												Executable Term Loans				Due Within One Year
Company	2014		2015		2016		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	238		35		—		1,030		1,303		1,303		53		—		53		185
Georgia Power	—		—		150		1,600		1,750		1,736		—		—		—		—
Gulf Power	75		35		165		—		275		275		50		—		50		60
Mississippi Power	135		—		165		—		300		300		25		40		65		70
Southern Power	—		—		—		500		500		500		—		—		—		—
Other	75		25		—		—		100		100		25		—		25		50
Total	$	523	$	95	$	480	$	4,130	$	5,228	$	5,214	$	153	$	40	$	193	$	365

(a) No credit arrangements expire in 2017.

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 three months of 2014:

Company(a)	Other Long-Term Debt Issuances		Other Long-Term Debt Redemptions(b)
	(in millions)
Georgia Power	$	1,000	$	1
Mississippi Power	250		1
Southern Power	1		1
Other	—		6
Total	$	1,251	$	9

(a) Southern Company, Alabama Power, and Gulf Power did not issue or redeem any long-term debt during the first three months of 2014.

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

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

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(UNAUDITED)

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 will 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.

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.

Southern Power

In March 2014, Southern Power issued an additional $0.6 million under a promissory note, due April 30, 2033, to Turner Renewable Energy, LLC (TRE) related to the financing of Campo Verde Solar, LLC.

In March 2014, Southern Power prepaid $0.8 million of long-term debt to TRE.

(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.

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(UNAUDITED)

Components of the net periodic benefit costs for the three months ended March 31, 2014 and 2013 were as follows:

Pension Plans	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power
	(in millions)
Three Months Ended March 31, 2014
Service cost	$	53		$	12		$	16		$	3		$	3
Interest cost	109			26			38			5			5
Expected return on plan assets	(161		)	(42		)	(57		)	(7		)	(7		)
Amortization:
Prior service costs	6			1			3			—			—
Net (gain)/loss	28			8			10			1			1
Net cost	$	35		$	5		$	10		$	2		$	2
Three Months Ended March 31, 2013
Service cost	$	58		$	13		$	17		$	3		$	3
Interest cost	97			23			34			4			5
Expected return on plan assets	(151		)	(39		)	(53		)	(6		)	(7		)
Amortization:
Prior service costs	7			2			3			—			—
Net (gain)/loss	50			13			19			2			2
Net cost	$	61		$	12		$	20		$	3		$	3

Postretirement Benefits	Southern Company			Alabama Power			Georgia Power			Gulf Power		Mississippi Power
	(in millions)
Three Months Ended March 31, 2014
Service cost	$	5		$	1		$	2		$	—	$	—
Interest cost	20			5			8			1		1
Expected return on plan assets	(15		)	(6		)	(6		)	—		—
Amortization:
Prior service costs	1			1			—			—		—
Net (gain)/loss	1			—			—			—		—
Net cost	$	12		$	1		$	4		$	1	$	1
Three Months Ended March 31, 2013
Service cost	$	6		$	2		$	2		$	—	$	—
Interest cost	19			5			8			1		1
Expected return on plan assets	(14		)	(6		)	(6		)	—		—
Amortization:
Transition obligation	1			—			1			—		—
Prior service costs	1			1			—			—		—
Net (gain)/loss	3			—			2			—		—
Net cost	$	16		$	2		$	7		$	1	$	1

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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 32.3% for the three months ended March 31, 2014 compared to 24.5% 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, state income tax credits, and beneficial changes in certain state income tax laws.

Alabama Power

Alabama Power's effective tax rate was 39.3% for the three months ended March 31, 2014 compared to 39.2% for the corresponding period in 2013.

Georgia Power

Georgia Power's effective tax rate was 38.0% for the three months ended March 31, 2014 compared to 38.1% for the corresponding period in 2013.

Gulf Power

Gulf Power's effective tax rate was 37.4% for the three months ended March 31, 2014 compared to 37.6% for the corresponding period in 2013.

Mississippi Power

Mississippi Power's effective tax rate was (43.0)% for the three months ended March 31, 2014 compared to (40.8)% for the corresponding period in 2013. The decrease 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 8.5% for the three months ended March 31, 2014 compared to 33.5% for the corresponding period in 2013. The decrease was primarily due to an increase in state 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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(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 uncontracted generating capacity. Further, the traditional operating companies may be 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.

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 March 31, 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	256	2018	2017
Alabama Power	65	2017	—
Georgia Power	53	2017	—
Gulf Power	83	2018	—
Mississippi Power	54	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 7 million mmBtu for Southern Company, 1 million mmBtu for Alabama Power, 4 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 revenue and fuel expense for the next 12-month period ending March 31, 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 March 31, 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) March 31, 2014
	(in millions)					(in millions)
Fair value hedges of existing debt
Southern Company	$	350	4.15%	3-month LIBOR  + 1.96%	May 2014	$	3

The estimated pre-tax gains (losses) that will be reclassified from accumulated OCI to interest expense for the next 12-month period ending March 31, 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.

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(UNAUDITED)

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 a cash flow hedge 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.

During the quarter ended March 31, 2014, Mississippi Power's fair value hedge was de-designated and the related ineffectiveness was recorded as a regulatory asset and was immaterial. At March 31, 2014, the fair value of the foreign currency derivatives outstanding was immaterial.

Derivative Financial Statement Presentation and Amounts

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

Asset Derivatives at March 31, 2014
	Fair Value
Derivative Category and Balance Sheet Location	Southern Company		Alabama Power		Georgia Power		Gulf Power		Mississippi Power		Southern Power
	(in millions)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets	$	36	$	11	$	8	$	10	$	7
Other deferred charges and assets	4		1		—		2		1
Total derivatives designated as hedging instruments for regulatory purposes	$	40	$	12	$	8	$	12	$	8	N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current assets	3		—		—		—		—		$	—
Total asset derivatives	$	43	$	12	$	8	$	12	$	8	$	—

Liability Derivatives at March 31, 2014
	Fair Value
Derivative Category and Balance Sheet Location	Southern Company		Alabama Power		Georgia Power		Gulf Power		Mississippi Power		Southern Power
	(in millions)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Liabilities from risk management activities	$	17	$	1	$	10	$	4	$	2
Other deferred credits and liabilities	26		5		6		9		6
Total liability derivatives	$	43	$	6	$	16	$	13	$	8	N/A

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(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 March 31, 2014 and December 31,

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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 March 31, 2014
	Fair Value
	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power			Southern Power
	(in millions)
Assets
Energy-related derivatives:
Energy-related derivatives presented in the Balance Sheet (a)	$	40		$	12		$	8		$	12		$	8		$	—
Gross amounts not offset in the Balance Sheet (b)	(33		)	(6		)	(8		)	(8		)	(5		)	—
Net energy-related derivative assets	$	7		$	6		$	—		$	4		$	3		$	—
Liabilities
Energy-related derivatives:
Energy-related derivatives presented in the Balance Sheet (a)	$	(43	)	$	(6	)	$	(16	)	$	(13	)	$	(8	)	$	—
Gross amounts not offset in the Balance Sheet (b)	33			6			8			8			5			—
Net energy-related derivative liabilities	$	(10	)	$	—		$	(8	)	$	(5	)	$	(3	)	$	—

(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.

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(UNAUDITED)

At March 31, 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 March 31, 2014
Derivative Category and Balance Sheet Location	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power
	(in millions)
Energy-related derivatives:
Other regulatory assets, current	$	(17	)	$	(1	)	$	(10	)	$	(4	)	$	(2	)
Other regulatory assets, deferred	(26		)	(5		)	(6		)	(9		)	(6		)
Other regulatory liabilities, current	36			11			8			10			7
Other regulatory liabilities, deferred	4			1			—			2			1
Total energy-related derivative gains (losses)	$	(3	)	$	6		$	(8	)	$	(1	)	$	—

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 months ended March 31, 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 months ended March 31, 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 months ended March 31, 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 substantial 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 months ended March 31, 2013. This third party hedging activity has been discontinued.

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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 March 31, 2014, the fair value of derivative liabilities with contingent features was immaterial for all registrants.

At March 31, 2014, the registrants' collateral posted with their derivative counterparties was immaterial. The maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, were $2 million and include certain agreements that could require collateral in the event that one or more Southern Company power pool participants has a credit rating change to below investment grade.

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

Southern Company, the traditional operating companies, and Southern Power are exposed to losses related to financial instruments in the event of counterparties' nonperformance. Southern Company, the traditional operating companies, and Southern Power only enter into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's and S&P or with counterparties who have posted collateral to cover potential credit exposure. Southern Company, the traditional operating companies, and Southern Power have also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate Southern Company's, the traditional operating companies', and Southern Power's exposure to counterparty credit risk. Therefore, Southern Company, the traditional operating companies, and Southern Power do not anticipate a material adverse effect on the financial statements as a result of counterparty nonperformance.

(I) ACQUISITIONS

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 is expected to begin commercial operation in May 2014. The output of the plant is contracted under a 20-year PPA with Southern California Edison Company, which will begin on the commercial operation date. The acquisition is in accordance with Southern Power's overall growth strategy.

Southern Power's acquisition of Adobe included cash consideration of approximately $94.4 million, of which $75.5 million was paid at closing, with the remainder to be paid upon completion of certain milestones. The allocation of purchase price to individual assets has not been finalized. As of the acquisition date, approximately $81 million was allocated to CWIP and the remainder to other assets. The acquisition did not include any contingent consideration and due diligence 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.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

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 $72 million and $78 million for the three months ended March 31, 2014 and March 31, 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 months ended March 31, 2014 and 2013 was as follows:

	Electric Utilities
	Traditional Operating Companies		Southern Power		Eliminations			Total		All Other			Eliminations			Consolidated
	(in millions)
Three Months Ended March 31, 2014:
Operating revenues	$	4,378	$	351	$	(102	)	$	4,627	$	41		$	(24	)	$	4,644
Segment net income (loss)(a)(b)	318		33		—			351		—			—			351
Total assets at March 31, 2014	$	59,854	$	4,404	$	(98	)	$	64,160	$	1,093		$	(415	)	$	64,838
Three Months Ended March 31, 2013:
Operating revenues	$	3,668	$	303	$	(86	)	$	3,885	$	35		$	(23	)	$	3,897
Segment net income (loss)(a)(c)	66		29		—			95		(16		)	2			81
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 March 31, 2014 includes a $380.0 million pre-tax charge ($234.7 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 three months ended March 31, 2013 includes $540.0 million in pre-tax charges ($333.5 million after tax) for estimated probable losses on the Kemper IGCC. See Note (B) under "Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" herein for additional information.

Products and Services

	Electric Utilities' Revenues
Period	Retail		Wholesale		Other		Total
	(in millions)
Three Months Ended March 31, 2014	$	3,858	$	604	$	165	$	4,627
Three Months Ended March 31, 2013	3,298		432		155		3,885

149

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
	Southern Company
#	(a)1	-	Base Salaries of Named Executive Officers.
	Alabama Power
#	(b)1	-	Base Salaries of Named Executive Officers.
	Georgia Power
#	(c)1	-	Base Salaries of Named Executive Officers.
	(c)2	-	Amendment No. 6, dated as of January 23, 2014, to Engineering, Procurement and Construction Agreement, dated as of April 8, 2008, between Georgia Power, for itself and as agent for Oglethorpe Power Corporation, Municipal Electric Authority of Georgia, and Dalton Utilities, as owners, and a consortium consisting of Westinghouse and Stone & Webster, Inc., as contractor, for Units 3 & 4 at the Vogtle Electric Generating Plant Site.
	Mississippi Power
#	(e)1	-	Base Salaries of Named Executive Officers.
	(24) Power of Attorney and Resolutions
	Southern Company
	(a)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 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.
	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.)

150

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.)
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.

151

(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.
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

152

THE SOUTHERN COMPANY

SIGNATURES

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

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

Date: May 8, 2014

153

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
	President and Chief Executive Officer
	(Principal Executive Officer)
By	Philip C. Raymond
	Executive Vice President, Chief Financial Officer, and Treasurer
	(Principal Financial Officer)
By	/s/ Melissa K. Caen
	(Melissa K. Caen, Attorney-in-fact)

Date: May 8, 2014

154

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

Date: May 8, 2014

155

GULF POWER COMPANY

SIGNATURES

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

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

Date: May 8, 2014

156

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

Date: May 8, 2014

157

SOUTHERN POWER COMPANY

SIGNATURES

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

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

Date: May 8, 2014

158

EX-10.A.1

Exhibit 10(a)1

BASE SALARIES OF NAMED EXECUTIVE OFFICERS

THE SOUTHERN COMPANY

The following are the annual base salaries, effective March 1, 2014 unless otherwise noted, of the Chief Executive Officer and Chief Financial Officer of The Southern Company (the “Company”) and certain other executive officers of the Company who served during 2013.

Thomas A. Fanning Chairman, President and Chief Executive Officer	$1,200,000
Art P. Beattie Executive Vice President and Chief Financial Officer	$673,498
W. Paul Bowers Executive Vice President of the Company, President and Chief Executive Officer of Georgia Power Company	$787,338
Kimberly S. Greene Executive Vice President and Chief Operating Officer	$650,000
Charles D. McCrary* Executive Vice President of the Company, President and Chief Executive Officer of Alabama Power Company	$803,247

*Resigned as President and Chief Executive Officer of Alabama Power Company March 1, 2014. Retirement effective May 1, 2014.

EX-10.B.1

EXHIBIT 10(b)1

BASE SALARIES OF NAMED EXECUTIVE OFFICERS

ALABAMA POWER COMPANY

The following are the annual base salaries, effective March 1, 2014 unless otherwise noted, of the Chief Executive Officer and Chief Financial Officer of Alabama Power Company and certain other executive officers of Alabama Power Company who served during 2013.

Charles D. McCrary* President and Chief Executive Officer; Executive Vice President of Southern Company	$803,247
Mark A. Crosswhite** President and Chief Executive Officer	$600,000
Philip C. Raymond*** Executive Vice President, Chief Financial Officer, and Treasurer	$350,864
James P. Heilbron*** Senior Vice President and Senior Production Officer	$244,419
Zeke W. Smith*** Executive Vice President	$350,876
Steven R. Spencer*** Executive Vice President	$473,374

*Resigned as President and Chief Executive Officer March 1, 2014. Retirement effective May 1, 2014.

**Effective March 1, 2014

***Salary effective March 17, 2014

EX-10.C.1

EXHIBIT 10(c)1

BASE SALARIES OF NAMED EXECUTIVE OFFICERS

GEORGIA POWER COMPANY

The following are the annual base salaries, effective March 1, 2014 unless otherwise noted, of the Chief Executive Officer and Chief Financial Officer of Georgia Power Company and certain other executive officers of Georgia Power Company who served during 2013.

W. Paul Bowers President and Chief Executive Officer	$787,338
W. Ron Hinson Executive Vice President, Chief Financial Officer, And Treasurer	$358,799
Ronnie R. Labrato* Executive Vice President, Chief Financial Officer, and Treasurer	$307,114
W. Craig Barrs Executive Vice President	$327,144
Joseph A. Miller Executive Vice President	$551,050
Anthony L. Wilson Executive Vice President	$353,266

*Retired March 31, 2013. Salary shown was Mr. Labrato’s salary effective March 1, 2013.

EX-10.C.2

Exhibit 10(c)2

Confidential Trade Secret Information - Subject to Restricted Procedures

AMENDMENT NO. 6

TO

ENGINEERING, PROCUREMENT AND CONSTRUCTION

AGREEMENT

BETWEEN

GEORGIA POWER COMPANY, FOR ITSELF AND AS AGENT

FOR OGLETHORPE POWER CORPORATION (AN ELECTRIC

MEMBERSHIP CORPORATION), MUNICIPAL ELECTRIC

AUTHORITY OF GEORGIA AND THE CITY OF DALTON,

GEORGIA, ACTING BY AND THROUGH ITS BOARD OF WATER,

LIGHT AND SINKING FUND COMMISSIONERS, AS OWNERS

AND

A CONSORTIUM CONSISTING OF WESTINGHOUSE ELECTRIC

COMPANY LLC AND STONE & WEBSTER, INC., AS

CONTRACTOR

FOR

UNITS 3 & 4 AT THE VOGTLE ELECTRIC GENERATING PLANT

SITE

IN WAYNESBORO, GEORGIA

DATED AS OF APRIL 8, 2008

Confidential Trade Secret Information - Subject to Restricted Procedures

AMENDMENT NO. 6 TO

ENGINEERING, PROCUREMENT AND CONSTRUCTION AGREEMENT

This AMENDMENT NO. 6 (this "Amendment") TO THE ENGINEERING, PROCUREMENT AND CONSTRUCTION AGREEMENT, dated April 8, 2008, as amended (the "Agreement") by and between GEORGIA POWER COMPANY, a Georgia corporation ("GPC"), acting for itself and as agent for OGLETHORPE POWER CORPORATION (AN ELECTRIC MEMBERSHIP CORPORATION), an electric membership corporation formed under the laws of the State of Georgia, MUNICIPAL ELECTRIC AUTHORITY OF GEORGIA, a public body corporate and politic and an instrumentality of the State of Georgia, and THE CITY OF DALTON, GEORGIA, an incorporated municipality in the State of Georgia acting by and through its Board of Water, Light and Sinking Fund Commissioners (hereinafter referred to collectively as “Owners”), and a consortium consisting of WESTINGHOUSE ELECTRIC COMPANY LLC, a Delaware limited liability company having a place of business in Monroeville, Pennsylvania ("Westinghouse"), and STONE & WEBSTER, INC. a Louisiana corporation having a place of business in Charlotte, North Carolina ("Stone & Webster") (hereinafter referred to collectively as "Contractor"), is entered into as of the 23rd day of January2014.

RECITALS

WHEREAS, Owners and Contractor entered into the Agreement, as of April 8, 2008, to provide for, among other things, the design, engineering, procurement, installation, construction and technical support of start-up and testing of equipment, materials and structures comprising the Facility;

WHEREAS, in connection with the construction of the Facility, certain of the Owners plan to enter into definitive loan guarantee agreements with the United States Department of Energy (“DOE”), pursuant to which the DOE would provide federal loan guarantees pursuant to Title XVII of the Energy Policy Act of 2005 (the “Title XVII”) with respect to certain borrowings of such Owners (any such definitive loan guarantee agreement, a “Definitive Loan Guarantee Agreement”);

WHEREAS, pursuant to Section 1702(k) of the Energy Policy Act, all laborers and mechanics employed by contractors and subcontractors in the performance of construction work financed in whole or in part by a loan guarantee under Title XVII must be paid wages at rates not less than those prevailing on projects of a character similar in the locality as determined by the Secretary of Labor in accordance with subchapter IV of Chapter 31 of Title 40 of the United States (the “Davis-Bacon Act”) and all regulations of the Department of Labor set forth in Parts 1, 3 and 5 of title 29 of the Code of Federal Regulations (the “Davis-Bacon Act Regulations”);

WHEREAS, pursuant to the Davis-Bacon Act Regulations, each Definitive Loan Guarantee Agreement will require that certain contract provisions be incorporated in each contract, agreement or other arrangement subject to the requirements of the Davis-Bacon Act and the Davis-Bacon Act Regulations; and

Confidential Trade Secret Information - Subject to Restricted Procedures

WHEREAS, the Parties agree that, with the exception of the changes expressly stated herein, this Amendment will not change the terms and conditions of the Agreement.

NOW, THEREFORE, in consideration of the recitals, the mutual promises herein and other good and valuable consideration, the receipt and sufficiency of which the Parties acknowledge, the Parties, intending to be legally bound, stipulate and agree as follows:

1.This Amendment shall not be effective until one or more Owners have entered into a Definitive Loan Guarantee Agreement. GPC shall provide prompt written notice to Contractor of the occurrence of such actions.

2.Revise Article 35, “Federal Acquisition Regulations Requirements,” to add a new Section 35.4, as follows:

“35.4Davis-Bacon Act Required Contract Clauses. The contract clauses contained under the heading “Davis-Bacon Act Required Contract Clauses” in Exhibit AA to this Agreement shall, as if set forth herein in full text, be incorporated into and form a part of this Agreement (and, for the avoidance of doubt, shall be considered a part of Article 35 for purposes of the provisions of Exhibit Y to this Agreement), and Contractor shall comply therewith if the amount of this Agreement and the circumstances surrounding its performance require any Owner to include such clauses in this Agreement.”

(a) The Parties will cooperate in seeking appropriate exemptions from disclosure under the Freedom of Information Act, 5 U.S.C. § 552, and associated regulations for certified payroll data provided to federal agencies in the course of compliance with the Davis-Bacon Act and the Davis-Bacon Act Regulations.

(b) The Parties will implement the DAVIS-BACON AND RELATED ACTS COMPLIANCE PROGRAM FOR VOGTLE UNITS 3&4 PROJECT, attached as Exhibit BB.

3.Add a new Exhibit AA to the Agreement, the text of which is set forth in Attachment A to this Amendment No. 6.

4.Add a new Exhibit BB to the Agreement, the text of which is set forth in Attachment B to this Amendment No. 6.

5.Miscellaneous.

5.1 Capitalized terms used herein and not defined herein have the meaning assigned in the Agreement.

5.2 This Amendment shall be construed in connection with and as part of the Agreement, and all terms, conditions, and covenants contained in the Agreement, except as herein modified, shall be and shall remain in full force and effect. The Parties hereto agree that they are bound by the terms, conditions and covenants of the Agreement as amended hereby.

Confidential Trade Secret Information - Subject to Restricted Procedures

5.3 This Amendment may be executed simultaneously in two or more counterparts, each of which shall be deemed and original but both of which together shall constitute one and the same instrument.

5.4 The validity, interpretation, and performance of this Amendment and each of its provisions shall be governed by the laws of the State of Georgia.

5.5 Except as expressly provided for in this Amendment, all other Articles, Sections and Exhibits of and to the Agreement remain unchanged.

IN WITNESS WHEREOF, the Parties have duly executed this Amendment as of the date first above written.

WESTINGHOUSE ELECTRIC COMPANY LLC
By:	/s/Scott W. Gray
Name: Scott W. Gray
Title: Vice President and Project Director
STONE & WEBSTER, INC.
By:	/s/Clarence Ray	/s/ Mark McKain
Name: Clarence Ray		Mark McKain
Title: Director
GEORGIA POWER COMPANY, as an Owner
and as agent for the other Owners
By:	/s/Joseph Miller
Name: Joseph (Buzz) Miller
Title: EVP - Nuclear Development

Confidential Trade Secret Information - Subject to Restricted Procedures

Attachment A to Amendment No. 6 to EPC Agreement (April 8, 2008)

The following sets forth the text of a new Exhibit AA to the EPC Agreement:

“Davis-Bacon Act Required Contract Clauses

SECTION (a) MINIMUM WAGES, ETC.

(1) Minimum wages.

(i) All laborers and mechanics employed or working upon the site of the work (or under the United States Housing Act of 1937 or under the Housing Act of 1949 in the construction or development of the project), will be paid unconditionally and not less often than once a week, and without subsequent deduction or rebate on any account (except such payroll deductions as are permitted by regulations issued by the Secretary of Labor under the Copeland Act (29 CFR part 3)), the full amount of wages and bona fide fringe benefits (or cash equivalents thereof) due at time of payment computed at rates not less than those contained in the wage determination of the Secretary of Labor which is attached hereto and made a part hereof, regardless of any contractual relationship which may be alleged to exist between the contractor and such laborers and mechanics.

Contributions made or costs reasonably anticipated for bona fide fringe benefits under section 1(b)(2) of the Davis-Bacon Act on behalf of laborers or mechanics are considered wages paid to such laborers or mechanics, subject to the provisions of paragraph (a)(1)(iv) of this section; also, regular contributions made or costs incurred for more than a weekly period (but not less often than quarterly) under plans, funds, or programs which cover the particular weekly period, are deemed to be constructively made or incurred during such weekly period. Such laborers and mechanics shall be paid the appropriate wage rate and fringe benefits on the wage determination for the classification of work actually performed, without regard to skill, except as provided in Sec. 5.5(a)(4) [paragraph (a)(4) below]. Laborers or mechanics performing work in more than one classification may be compensated at the rate specified for each classification for the time actually worked therein: Provided, That the employer's payroll records accurately set forth the time spent in each classification in which work is performed. The wage determination (including any additional classification and wage rates conformed under paragraph (a)(1)(ii) of this section) and the Davis-Bacon poster (WH-1321) shall be posted at all times by the contractor and its subcontractors at the site of the work in a prominent and accessible place where it can be easily seen by the workers.

(ii)(A) The contracting officer shall require that any class of laborers or mechanics, including helpers, which is not listed in the wage determination and which is to be employed under the contract shall be classified in conformance with the wage determination. The contracting officer shall approve an additional classification and wage rate and fringe benefits therefore only when the following criteria have been met:

(1) The work to be performed by the classification requested is not

Confidential Trade Secret Information - Subject to Restricted Procedures

performed by a classification in the wage determination; and

(2) The classification is utilized in the area by the construction industry; and

(3) The proposed wage rate, including any bona fide fringe benefits, bears a reasonable relationship to the wage rates contained in the wage determination.

(ii)(B) If the contractor and the laborers and mechanics to be employed in the classification (if known), or their representatives, and the contracting officer agree on the classification and wage rate (including the amount designated for fringe benefits where appropriate), a report of the action taken shall be sent by the contracting officer to the Administrator of the Wage and Hour Division, Employment Standards Administration, U.S. Department of Labor, Washington, DC 20210. The Administrator, or an authorized representative, will approve, modify, or disapprove every additional classification action within 30 days of receipt and so advise the contracting officer or will notify the contracting officer within the 30-day period that additional time is necessary.

(ii)(C) In the event the contractor, the laborers or mechanics to be employed in the classification or their representatives, and the contracting officer do not agree on the proposed classification and wage rate (including the amount designated for fringe benefits, where appropriate), the contracting officer shall refer the questions, including the views of all interested parties and the recommendation of the contracting officer, to the Administrator for determination. The Administrator, or an authorized representative, will issue a determination within 30 days of receipt and so advise the contracting officer or will notify the contracting officer within the 30-day period that additional time is necessary.

(ii)(D) The wage rate (including fringe benefits where appropriate) determined pursuant to paragraphs (a)(1)(ii) (B) or (C) of this section, shall be paid to all workers performing work in the classification under this contract from the first day on which work is performed in the classification.

(iii) Whenever the minimum wage rate prescribed in the contract for a class of laborers or mechanics includes a fringe benefit which is not expressed as an hourly rate, the contractor shall either pay the benefit as stated in the wage determination or shall pay another bona fide fringe benefit or an hourly cash equivalent thereof.

(iv) If the contractor does not make payments to a trustee or other third person, the contractor may consider as part of the wages of any laborer or mechanic the amount of any costs reasonably anticipated in providing bona fide fringe benefits under a plan or program, Provided, That the Secretary of Labor has found, upon the written request of the contractor, that the applicable standards of the Davis-Bacon Act have been met. The Secretary of Labor may require the contractor to set aside in a separate account assets for the meeting of obligations under the plan or program.

(2) Withholding.

Confidential Trade Secret Information - Subject to Restricted Procedures

The Department of Energy ("DOE") shall upon its own action or upon written request of an authorized representative of the Department of Labor withhold or cause to be withheld from the contractor under this contract or any other Federal contract with the same prime contractor, or any other federally-assisted contract subject to Davis-Bacon prevailing wage requirements, which is held by the same prime contractor, so much of the accrued payments or advances as may be considered necessary to pay laborers and mechanics, including apprentices, trainees, and helpers, employed by the contractor or any subcontractor the full amount of wages required by the contract. In the event of failure to pay any laborer or mechanic, including any apprentice, trainee, or helper, employed or working on the site of the work (or under the United States Housing Act of 1937 or under the Housing Act of 1949 in the construction or development of the project), all or part of the wages required by the contract, DOE may, after written notice to the contractor, sponsor, applicant, or owner, take such action as may be necessary to cause the suspension of any further payment, advance, or guarantee of funds until such violations have ceased.

(3) Payrolls and basic records.

(i) Payrolls and basic records relating thereto shall be maintained by the contractor during the course of the work and preserved for a period of three years thereafter for all laborers and mechanics working at the site of the work (or under the United States Housing Act of 1937, or under the Housing Act of 1949, in the construction or development of the project). Such records shall contain the name, address, and social security number of each such worker, his or her correct classification, hourly rates of wages paid (including rates of contributions or costs anticipated for bona fide fringe benefits or cash equivalents thereof of the types described in section 1(b)(2)(B) of the Davis-Bacon Act), daily and weekly number of hours worked, deductions made and actual wages paid. Whenever the Secretary of Labor has found under 29 CFR 5.5(a)(1)(iv) that the wages of any laborer or mechanic include the amount of any costs reasonably anticipated in providing benefits under a plan or program described in section 1(b)(2)(B) of the Davis-Bacon Act, the contractor shall maintain records which show that the commitment to provide such benefits is enforceable, that the plan or program is financially responsible, and that the plan or program has been communicated in writing to the laborers or mechanics affected, and records which show the costs anticipated or the actual cost incurred in providing such benefits. Contractors employing apprentices or trainees under approved programs shall maintain written evidence of the registration of apprenticeship programs and certification of trainee programs, the registration of the apprentices and trainees, and the ratios and wage rates prescribed in the applicable programs.

(ii)(A) The contractor shall submit weekly for each week in which any contract work is performed a copy of all payrolls to the DOE) if the agency is a party to the contract, but if the agency is not such a party, the contractor will submit the payrolls to the applicant, sponsor, or owner, as the case may be, for transmission to DOE. The payrolls submitted shall set out accurately and completely all of the information required to be maintained under 29 CFR 5.5(a)(3)(i), except that full social security numbers and home addresses

Confidential Trade Secret Information - Subject to Restricted Procedures

shall not be included on weekly transmittals. Instead the payrolls shall only need to include an individually identifying number for each employee (e.g., the last four digits of the employee's social security number). The required weekly payroll information may be submitted in any form desired. Optional Form WH-347 is available for this purpose from the Wage and Hour Division Web site at http://www.dol.gov/esa/whd/forms/wh347instr.htm or its successor site. The prime contractor is responsible for the submission of copies of payrolls by all subcontractors. Contractors and subcontractors shall maintain the full social security number and current address of each covered worker, and shall provide them upon request to DOE if the agency is a party to the contract, but if the agency is not such a party, the contractor will submit them to the applicant, sponsor, or owner, as the case may be, for transmission to DOE, the contractor, or the Wage and Hour Division of the Department of Labor for purposes of an investigation or audit of compliance with prevailing wage requirements. It is not a violation of this section for a prime contractor to require a subcontractor to provide addresses and social security numbers to the prime contractor for its own records, without weekly submission to the sponsoring government agency (or the applicant, sponsor, or owner).

(ii)(B) Each payroll submitted shall be accompanied by a ``Statement of Compliance,'' signed by the contractor or subcontractor or his or her agent who pays or supervises the payment of the persons employed under the contract and shall certify the following:

(1) That the payroll for the payroll period contains the information required to be provided under Sec. 5.5 (a)(3)(ii) of Regulations, 29 CFR part 5, the appropriate information is being maintained under Sec. 5.5 (a)(3)(i) of Regulations, 29 CFR part 5, and that such information is correct and complete;

(2) That each laborer or mechanic (including each helper, apprentice, and trainee) employed on the contract during the payroll period has been paid the full weekly wages earned, without rebate, either directly or indirectly, and that no deductions have been made either directly or indirectly from the full wages earned, other than permissible deductions as set forth in Regulations, 29 CFR part 3;

(3) That each laborer or mechanic has been paid not less than the applicable wage rates and fringe benefits or cash equivalents for the classification of work performed, as specified in the applicable wage determination incorporated into the contract.

(ii)(C) The weekly submission of a properly executed certification set forth on the reverse side of Optional Form WH-347 shall satisfy the requirement for submission of the ``Statement of Compliance'' required by paragraph (a)(3)(ii)(B) of this section.

(ii)(D) The falsification of any of the above certifications may subject the contractor or subcontractor to civil or criminal prosecution under section 1001 of title 18 and section 231 of title 31 of the United States Code.

(iii) The contractor or subcontractor shall make the records required under paragraph (a)(3)(i) of this section available for inspection, copying, or transcription by authorized representatives of DOE or the Department of Labor, and shall permit

Confidential Trade Secret Information - Subject to Restricted Procedures

such representatives to interview employees during working hours on the job. If the contractor or subcontractor fails to submit the required records or to make them available, the Federal agency may, after written notice to the contractor, sponsor, applicant, or owner, take such action as may be necessary to cause the suspension of any further payment, advance, or guarantee of funds. Furthermore, failure to submit the required records upon request or to make such records available may be grounds for debarment action pursuant to 29 CFR 5.12.

(4) Apprentices and trainees

(i) Apprentices. Apprentices will be permitted to work at less than the predetermined rate for the work they performed when they are employed pursuant to and individually registered in a bona fide apprenticeship program registered with the U.S. Department of Labor, Employment and Training Administration, Office of Apprenticeship Training, Employer and Labor Services, or with a State Apprenticeship Agency recognized by the Office, or if a person is employed in his or her first 90 days of probationary employment as an apprentice in such an apprenticeship program, who is not individually registered in the program, but who has been certified by the Office of Apprenticeship Training, Employer and Labor Services or a State Apprenticeship Agency (where appropriate) to be eligible for probationary employment as an apprentice. The allowable ratio of apprentices to journeymen on the job site in any craft classification shall not be greater than the ratio permitted to the contractor as to the entire work force under the registered program. Any worker listed on a payroll at an apprentice wage rate, who is not registered or otherwise employed as stated above, shall be paid not less than the applicable wage rate on the wage determination for the classification of work actually performed. In addition, any apprentice performing work on the job site in excess of the ratio permitted under the registered program shall be paid not less than the applicable wage rate on the wage determination for the work actually performed. Where a contractor is performing construction on a project in a locality other than that in which its program is registered, the ratios and wage rates (expressed in percentages of the journeyman's hourly rate) specified in the contractor's or subcontractor's registered program shall be observed. Every apprentice must be paid at not less than the rate specified in the registered program for the apprentice's level of progress, expressed as a percentage of the journeymen hourly rate specified in the applicable wage determination. Apprentices shall be paid fringe benefits in accordance with the provisions of the apprenticeship program. If the apprenticeship program does not specify fringe benefits, apprentices must be paid the full amount of fringe benefits listed on the wage determination for the applicable classification. If the Administrator determines that a different practice prevails for the applicable apprentice classification, fringes shall be paid in accordance with that determination. In the event the Office of Apprenticeship Training, Employer and Labor Services, or a State Apprenticeship Agency recognized by the Office, withdraws approval of an apprenticeship program, the contractor will no longer be permitted to utilize apprentices at less than the applicable predetermined rate for the work performed until an acceptable program is approved.

Confidential Trade Secret Information - Subject to Restricted Procedures

(ii) Trainees. Except as provided in 29 CFR 5.16, trainees will not be permitted to work at less than the predetermined rate for the work performed unless they are employed pursuant to and individually registered in a program which has received prior approval, evidenced by formal certification by the U.S. Department of Labor, Employment and Training Administration. The ratio of trainees to journeymen on the job site shall not be greater than permitted under the plan approved by the Employment and Training Administration. Every trainee must be paid at not less than the rate specified in the approved program for the trainee's level of progress, expressed as a percentage of the journeyman hourly rate specified in the applicable wage determination. Trainees shall be paid fringe benefits in accordance with the provisions of the trainee program. If the trainee program does not mention fringe benefits, trainees shall be paid the full amount of fringe benefits listed on the wage determination unless the Administrator of the Wage and Hour Division determines that there is an apprenticeship program associated with the corresponding journeyman wage rate on the wage determination which provides for less than full fringe benefits for apprentices. Any employee listed on the payroll at a trainee rate who is not registered and participating in a training plan approved by the Employment and Training Administration shall be paid not less than the applicable wage rate on the wage determination for the classification of work actually performed. In addition, any trainee performing work on the job site in excess of the ratio permitted under the registered program shall be paid not less than the applicable wage rate on the wage determination for the work actually performed. In the event the Employment and Training Administration withdraws approval of a training program, the contractor will no longer be permitted to utilize trainees at less than the applicable predetermined rate for the work performed until an acceptable program is approved.

(iii) Equal employment opportunity. The utilization of apprentices, trainees and journeymen under this part shall be in conformity with the equal employment opportunity requirements of Executive Order 11246, as amended, and 29 CFR part 30.

(5) Compliance with Copeland Act requirements.

The contractor shall comply with the requirements of 29 CFR part 3, which are incorporated by reference in this contract.

(6) Subcontracts.

The contractor or subcontractor shall insert in any subcontracts the clauses contained in 29 CFR 5.5(a)(1) through (10) and such other clauses as DOE may by appropriate instructions require, and also a clause requiring the subcontractors to include these clauses in any lower tier subcontracts. The prime contractor shall be responsible for the compliance by any subcontractor or lower tier subcontractor with all the contract clauses in 29 CFR 5.5.

Confidential Trade Secret Information - Subject to Restricted Procedures

(7) Contract termination: debarment.

A breach of the contract clauses in 29 CFR 5.5 may be grounds for termination of the contract, and for debarment as a contractor and a subcontractor as provided in 29 CFR 5.12.

(8) Compliance with Davis-Bacon and Related Act requirements.

All rulings and interpretations of the Davis-Bacon and Related Acts contained in 29 CFR parts 1, 3, and 5 are herein incorporated by reference in this contract.

(9) Disputes concerning labor standards.

Disputes arising out of the labor standards provisions of this contract shall not be subject to the general disputes clause of this contract. Such disputes shall be resolved in accordance with the procedures of the Department of Labor set forth in 29 CFR parts 5, 6, and 7. Disputes within the meaning of this clause include disputes between the contractor (or any of its subcontractors) and the contracting agency, the U.S. Department of Labor, or the employees or their representatives.

(10) Certification of eligibility.

(i) By entering into this contract, the contractor certifies that neither it (nor he or she) nor any person or firm who has an interest in the contractor's firm is a person or firm ineligible to be awarded Government contracts by virtue of section 3(a) of the Davis-Bacon Act or 29 CFR 5.12(a)(1).

(ii) No part of this contract shall be subcontracted to any person or firm ineligible for award of a Government contract by virtue of section 3(a) of the Davis-Bacon Act or 29 CFR 5.12(a)(1).

(iii) The penalty for making false statements is prescribed in the U.S. Criminal Code, 18 U.S.C. 1001.”

Attachment B to Amendment No. 6 to EPC Agreement (April 8, 2008)

Davis-Bacon and Related Acts

Compliance Program

For Vogtle Units 3 & 4 Project

TABLE OF CONTENTS

Title		Page
Article 1:	Introduction	3
Article 2:	The Davis-Bacon and Related Acts	6
Article 3:	DBRA Guidance	8
Article 4:	DBRA Compliance Process	11

Appendix
	1.	Contractor / Subcontractor Compliance Package		15
		a.	DBA Cover Letter to CLA Subcontractors	15
		b.	DBA Cover Letter to non-CLA Subcontractors	21
		c.	Required DBA Contract Language	26
		d.	DBRA Compliance Outline for CLA Contractors	35
		e.	DBRA Compliance Outline for non-CLA Contractors	51
		f.	Area Wage Determinations	67
	2.	PwC Agreed Upon Procedures (AUP)		81

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ARTICLE 1: INTRODUCTION

1.Purpose

(a)The purpose of this Compliance Program is to explain how all entities involved on the Vogtle Units 3 & 4 Project (“Project”) will comply with the requirements of the Davis-Bacon and Related Acts (DBRA). The Compliance Program employs a streamlined web-based solution of simplicity to acquire the requisite payroll data, provides transparency of certified payrolls through eMars web-based certified payroll software and guarantees accountability through monitoring and compliance activities. The documents referenced herein are provided in the Appendix. All Parties in Article 1, Section 3 below agree to abide by this Compliance Program.

2.The Project

(a)Georgia Power Company, Oglethorpe Power Corporation, Municipal Electric Authority of Georgia, and Dalton Utilities (collectively “Owners”) are currently constructing two new nuclear reactors in Burke County, Georgia, known as Vogtle Units 3 & 4 (“Vogtle 3 & 4”). These will be the first new nuclear reactors built in the United States in over 30 years.

(b)Vogtle 3 & 4 will use two Westinghouse “AP1000” (Advanced Pressurized) nuclear units. The AP1000 is the safest and most economical nuclear power plant available in the worldwide commercial marketplace, and is the only Generation III+ reactor to receive Design Certification from the U.S. Nuclear Regulatory Commission (NRC). Each nuclear unit will have a generating capacity of approximately 1,100 megawatts.

(c)Excavation of the sites for Vogtle 3 & 4 began in 2009, and construction is ongoing. Vogtle Units 3 & 4 are expected to be placed in service in 2017 and 2018 respectively.

3.The Parties

(a)The owners (collectively “Owners”) of this Project and their respective ownership interests are as follows:

(1)Georgia Power Company (GPC) - 45.7%;

(2)Oglethorpe Power Corporation - 30%;

(3)Municipal Electric Authority of Georgia - 22.7%; and

(4)Dalton Utilities - 1.6%.

(b)The Owners have designated GPC as the lead owner in charge of administering Davis-Bacon Act compliance and this Compliance Program. This Compliance Program is intended to encompass all of the Parties’ DBRA compliance obligations.

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(c)The Owners have hired Southern Nuclear Operating Company (“Southern Nuclear”) to be the Operator of the Vogtle 3 & 4 Project.

(d)Southern Company (“SO”) is the parent company of GPC and Southern Nuclear.

(e)Southern Company Services (“SCS”) is a shared services subsidiary of Southern Company.

(f)The Owners entered into an Engineering, Procurement and Construction (“EPC”) agreement with Stone and Webster, Inc. (“Stone and Webster”) and Westinghouse Electric Company, LLC (“Westinghouse”). In February of 2013, Stone and Webster became a wholly-owned subsidiary of Chicago Bridge & Iron (“CB&I”).

(g)Stone and Webster and Westinghouse are collectively referred to as the “Consortium.”

(h)The Owners and Consortium may be referred to individually as a “Party” and collectively as the “Parties.”

(i)The Nuclear Power Construction Labor Agreement (CLA) is one of the collective bargaining agreements among the various contractors and labor unions that will perform construction work on this Project.

(j)eMars is a web-based DBRA certified payroll reporting system that all DBRA-covered contractors and subcontractors will use on this Project.

(k)PricewaterhouseCoopers (PwC) has developed an “Agreed Upon Procedures” (AUP) program to conduct compliance activities and monitor ongoing DBRA compliance on the Project.

4.Primary DBRA Contacts

(a)SO / GPC - Christopher S. Miller

SCS VP and Associate General Counsel

(b)Consortium

(1)Mary Yerace

Site Davis Bacon Administrator, CB&I

(2)Joseph (“Lee”) Woodcock

Site Contract Manager, Westinghouse Electric Company

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(c)eMars - Woodrow Chamberlain

President eMars

(d)AUP / PwC - Christopher Lorenz

5.Project Timeline

(a)A timeline of events pertinent to Vogtle Units 3 and 4 and DBRA coverage is as follows:

(1)2005 - Initial planning and preparation for a new nuclear plant.

(2)April 8, 2008 - EPC Agreement signed. Compliance with Davis Bacon and Related Acts was not contemplated at the time of the contract.

(3)April 2009 - GPC provided the Westinghouse-Shaw Consortium full notice to proceed on Plant Vogtle Units 3 and 4. Shaw and Westinghouse began mobilizing at the plant site and performing activities to support construction.

(4)August 2009 - Excavation of the area where the new units are planned began at the plant site.

(5)October 28, 2009 - Energy Policy Act of 2005 is revised, and Section 1702(k) is added requiring DBRA compliance.

(6)February 16, 2010 - In response to GPC’s conditional loan guarantee request, President Obama and DOE Secretary Steven Chu announce the award of conditional loan guarantees for Vogtle Units 3 and 4.

(7)March 1, 2010 - Nuclear Power Construction Labor Agreement signed.

(8)June 18, 2010 - Southern Company and the Department of Energy announce that preliminary terms and conditions have been reached regarding the loan guarantees for the new Vogtle units.

(9)June 18, 2010 - The Department of Labor approves a waiver of any retroactive application of the Davis-Bacon Act and confirms that the Davis-Bacon Act will not apply until the closing of the loan guarantee.

(10)February 12, 2012 - Combined Operating License (COL) issued.

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(11)Late 2013 - Projected closing on the loan guarantee.

(12)2017 - Unit 3 projected to begin commercial operation.

(13)2018 - Unit 4 projected to begin commercial operation.

(b)For a more detailed timeline including construction details and other regulatory activities, see http://www.southerncompany.com/nuclearenergy/milestones.aspx.

ARTICLE2: THE DAVIS-BACON AND RELATED ACTS

1.Overview of the DBRA and the Basis for DBRA Coverage

(a)For purposes of this Compliance Program, the term Davis-Bacon and Related Acts (DBRA) refers to two federal statutes: the Davis-Bacon Act (40 U.S.C. § 3141), and the Copeland “Anti-Kickback” Act (40 U.S.C. § 3145 and 18 U.S.C. § 874. The Davis-Bacon Act (“DBA”) requires the payment of locally prevailing wages and fringe benefits, as defined in the applicable wage determination, to laborers and mechanics employed for construction, alteration or repair on the site of the work. Contractors and subcontractors must pay their workers weekly and must submit weekly certified payrolls. The Copeland Anti-Kickback Act prohibits the kickbacks of wages and back wages from employees to employers.

(b)The Davis-Bacon Act was enacted in 1931 to ensure that local workers were hired and paid locally prevailing wages on federal construction projects during the Great Depression. The original intention of the DBA contemplated the Federal Government as the

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owner of the project and as a party to the contract for the construction of a public building or public work for the Government. However, Congress and the Department of Labor (DOL) have since expanded the reach of the DBA and made it applicable to other construction contracts, to which the Federal Government is not a party. Here, the Department of Energy (DOE) has reached an agreement with GPC to provide a loan guarantee for the Vogtle 3 & 4 construction through the Energy Policy Act of 2005. Section 1702(k) was added to the Energy Policy Act in October 2009 and requires the payment of DBA wages on all construction projects funded under this Section. Therefore, the DBRA is applicable to Vogtle 3 & 4.

2.Beginning of DBRA Compliance

(a)Based on a request from the Department of Energy (DOE), the DOE and GPC have received written confirmation from the Department of Labor (DOL) that the DBRA will not apply to this Project prior to the closing of the loan guarantee. The DOL also confirmed that the DBRA will apply to the Project after the closing of the Loan Guarantee Agreement (LGA), which DOE acknowledges in the LGA . As indicated in the timeline above, the closing is anticipated in late 2013.

3.DBRA Roles & Obligations

(a)As an Owner of the Project and as the loan guarantee recipient from the DOE, GPC is responsible for compliance by contractors and subcontractors on this Project.

(1)GPC will be responsible for submitting all certified payrolls for all contractors and subcontractors each week to the DOE. 29 C.F.R. § 5.5(a)(3)(ii)(A).

(2)GPC will also be the point of contact for all communications with the DOE / DOL.

(b)Each Consortium member will be responsible for using reasonable efforts to ensure that it and all of its contractors and subcontractors comply with the applicable DBRA requirements and obligations including those identified in this Compliance Program.

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ARTICLE 3: DBRA GUIDANCE

1.Guidance

(a)Guidance for DBRA compliance can be found in the Contractor / Subcontractor Compliance Package in Appendix 1.

(b)Appendix 1 contains the following information:

(1)an initial cover letter (for contractor’s optional use) to any contractors or subcontractors working on the Project explaining that the DBRA applies to this Project and identifying their obligations (Appx. 1a and 1b);

(2)DBRA contract language that must be inserted into any and all contracts or subcontracts which fall within the scope of the Davis-Bacon Act and which are in effect on or after the closing of the loan guarantee agreement (Appx. 1c);

(3)a DBRA Compliance Outline of What Your Organization Must Do to Meet Its Responsibilities (Appx. 1d and 1e); and

(4)the applicable Area Wage Determinations (AWD) for Heavy, Building, and Highway construction in Burke County, Georgia (Appx. 1f).

(c)All contractors and subcontractors should closely review, analyze, and utilize these documents throughout construction of the Project.

(d)Some of the Davis-Bacon Act requirements for all contractors and subcontractors include:

(1)paying prevailing wages and fringe benefits;

(2)paying workers weekly;

(3)submitting certified payrolls;

(4)keeping records; and

(5)posting notices.

For all DBRA requirements, see Appendix 1 and 29 C.F.R. § 5 (excluding §5.5(b)).

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2. Southern Nuclear Davis-Bacon Act Compliance Roles and Responsibilities

(a)The key SO personnel with DBRA responsibility will be:

(1)SCS DBA Compliance Specialist [title subject to change]

i.The SCS DBA Compliance Specialist will be responsible for the overall day-to-day activities surrounding DBRA compliance. He or she will ensure that a weekly certified payroll is entered in eMars every week for every DBRA-covered contractor or subcontractor and will contact the responsible party, either Stone and Webster or Westinghouse, for any sub-tier contractors whose payrolls are delinquent or incomplete, or contain compliance errors/issues. The SCS DBA Compliance Specialist will report any DBA-related complaints he or she receives to the SCS VP, Employee Relations.

(2)SCS DBA Compliance Liaison [title subject to change]

i.The SCS DBA Compliance Liaison will supervise the SCS DBA Compliance Specialist, verify that DBA contract clauses are inserted into all DBRA-covered contracts and subcontracts, and act as a liaison between SO and the Consortium. The SCS DBA Compliance Liaison will report any DBA-related complaints he or she receives to the SCS VP, Employee Relations.

(3)VP, Vogtle 3 & 4 Construction Support

i.The VP-Vogtle 3 & 4 Construction Support will work to ensure DBA compliance and communicate any instructions regarding DBRA compliance to all contractors and subcontractors. The VP, Vogtle 3 & 4 Construction Support will report any DBA-related complaints he or she receives to the SCS VP, Employee Relations.

(4)SCS VP, Employee Relations

i.The SCS VP, Employee Relations is responsible for all communications with the DOE / DOL related to DBRA compliance, including the reporting of DBA-related complaints.

(b)Complaints. All DBRA-related complaints received through any Company channels must be reported to one of the key SO personnel identified in Article 2(a) above. Such channels shall include:

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(1)DBRA-related complaints received by any on-site SNC, GPC, or SCS managers, or Co-Owners’ on-site management

(2)DBRA-related complaints received through the Concerns hotline

i. Confidentiality of the Concerns program will be respected. However, investigation reports will be forwarded to the SCS VP, Employee Relations.

3.Consortium Davis-Bacon Act Compliance Roles and Responsibilities

(a)The key Consortium personnel with DBRA responsibility will be:

(1)DBA Compliance Specialist, or similar employee of Consortium, will be responsible for communicating the importance of DBRA compliance and be available to answer questions regarding compliance for all subcontractors on the project. DBA Compliance Specialist will also act as a resource by informing appropriate subcontractor personnel of available training material for eMars.

(b)Complaints. All DBRA-related complaints received by the Consortium must be reported to one of the key SO personnel identified in Article 2(a) above. Such channels shall include:

(1)DBRA-related complaints received through Consortium channels (e.g. DBA Compliance Specialist, Labor Relations, Payroll, Concerns program).

(2)Grievances filed under the CLA related specifically to DBRA-related issues.

i.SO will defer to the existing grievance process for the investigation and disposition of DBRA-related grievances. However, a report on the content and disposition of such grievances shall be provided to the SCS VP, Employee Relations, on a quarterly basis.

(c)DOE/DOL DBRA Adverse Determinations. Any resolution of a DBRA dispute with DOE/DOL by a Consortium member or contractor at any tier must be promptly reported to the SCS VP, Employee Relations, for his review and consent, such consent not to be unreasonably withheld. In addition to the reporting responsibilities, should any Consortium member or contractor at any tier receive an adverse DOE/DOL DBRA determination and not resolve it with DOE/DOL, and the Consortium member or contractor desires to appeal the determination through DOL’s administrative/enforcement processes, the Consortium member/contractor shall first request permission from the SCS VP, Employee Relations to do so, such consent not to be unreasonably withheld. Similarly, the Owners may request the Consortium member/contractor to appeal an adverse DOE/DOL DBRA determination, such consent not to be unreasonably withheld. In either situation, the requesting party shall assume all costs relating to the appeal and subsequent administrative/judicial proceedings including any

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judgment or withholding of contract funds and the requesting party shall indemnify and hold harmless the non-requesting party for all costs, including any judgment or withholding of contract funds resulting from the appeal.

4.Mutual Notice and Cooperation

Each party agrees to promptly notify the other Party of the existence of any DBRA dispute with the DOE/DOL or any other potential non-compliance issue (collectively referred to as a “Compliance Issue”) with respect to the Project. The Parties further agree to cooperate with respect to any action (e.g. corrective action, payment under the applicable contract, continuation, termination, etc.) that either Party takes in connection with a Compliance Issue to the extent such action is reasonable and consistent with the agreement between the Parties regarding the Consortium’s DBRA compliance.

ARTICLE 4: DBRA COMPLIANCE PROCESS

1.DBRA Compliance Objectives

(a)To create a process and procedure to:

(1)Simply input and acquire the requisite payroll data through a web-based certified payroll reporting system;

(2) Securely verify and store all certified payrolls, while simultaneously providing transparency and an audit trail for the DOE/DOL; and

(3)Hold parties accountable through monitoring and compliance activities.

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2.Simplicity

(a)One of the goals of this DBRA Compliance Program is to simplify inputting, collecting, and submitting certified payrolls pursuant to DBRA.

(b)All DBRA-covered contractors and subcontractors will use eMars, a web-based service, to enter, store, and submit their certified payrolls pursuant to DBRA.

(c)eMars allows contractors and subcontractors to quickly and easily submit certified payrolls electronically. It also provides the ability to electronically certify and sign certified payrolls.

(d)eMars permits contractors and subcontractors to manually input their payrolls, or they can import certified payroll information from their existing electronic payroll systems.

(e)GPC is providing all contractors and subcontractors, with training and access to the eMars program, at no cost to them; GPC will cover the cost of access to and use of the eMars program.

3.Transparency

(a)Transparency in certified payrolls and in other DBRA obligations is mandated by law and enforced by the DOL / DOE.

(b)eMars will automatically check submitted certified payrolls for errors, including incorrect wage rates, improper deductions, improper job classifications not found on the wage determination, missing apprenticeship certificates, etc.

(c)eMars will instantaneously notify the contractor or subcontractor who submitted the certified payroll of any errors or other problems, and the contractor or subcontractor will have an opportunity to correct errors immediately and submit a revised certified payroll.

(d)eMars will also provide full access to all certified payroll data and to other basic records to the DOL / DOE at their request. The DOL / DOE will be able to review a clear audit trail, including all previous versions of certified payrolls and any corrections, deficiencies, etc.

(1)Even though the EPC agreement contains confidentiality conditions regarding the receipt, use, or release of the Consortium’s project costs, the DBRA mandates that all contractors or subcontractors “make the records … available for inspection” by the DOE / DOL. 29 C.F.R.§ 5.5(a)(3)(iii). Failure to provide access to the records may result in a breach of GPC's obligations in the Loan Guarantee Agreement and/or contractor debarment.

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(2)GPC agrees that if DOE receives a FOIA request for the certified payrolls, GPC will request that DOE designate such certified payrolls as exempt from delivery in connection with any such FOIA request.  However, GPC understands that DOE is obligated under FOIA to deliver information requested in a FOIA request unless such information is exempt from disclosure in accordance with all applicable law, and, therefore, GPC cannot warrant or guarantee that DOE will designate such certified payrolls as exempt from delivery under FOIA.  If GPC is notified by DOE that DOE has received a FOIA request involving Consortium members or their subcontractors or organizations doing business with them, GPC will identify to DOE both Consortium members as parties to be notified.  Upon any such notice from GPC to the Consortium members, the Consortium members shall be responsible for notifying the subcontractor or organization doing business with them at any tier to the extent such organization's records have been requested.

4.Accountability

(a)As prime contractor, GPC is responsible for submitting all certified payrolls for all contractors and subcontractors each week to the DOE. 29 C.F.R. § 5.5(a)(3)(ii)(A).

(b)The EPC agreement between GPC and the Consortium has strict confidentiality provisions. The Consortium considers their project costs to be a confidential trade secret.

(c)In order for GPC to satisfactorily confirm DBRA compliance by all contractors and subcontractors on the Project, monitoring and compliance activities will occur at various levels and by various entities.

(d)SCS personnel will perform periodic reviews of certified payrolls submitted by all contractors and subcontractors.

(1)All SO personnel who have access to the eMars system will sign a Non-Disclosure Agreement related to information accessed through eMars. The use of such information shall be specifically limited to DBA compliance purposes and may not be disclosed except as otherwise required under statute/regulations. Such personnel shall be limited to:

i.SCS DBA Compliance Specialist (referenced in Article 3(2)(a)(1) of this Compliance Program)

ii.SCS DBA Compliance Liaison (referenced in Article 3(2)(a)(2) of this Compliance Program)

iii.SCS employees working in the Employee Relations/General Counsel organization

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iv.SCS employees working in the Internal Auditing organization

(e)The Consortium will have full access to all of their contractors’ and subcontractors’ certified payrolls in the eMars system.

(1)This access will allow the Consortium to review whether its contractors and subcontractors have timely submitted certified payrolls, whether those payrolls have any error warnings, what those error warnings are, the amount of any deficiency, apprentice certificates, etc.

(f)Finally, PricewaterhouseCoopers (PwC) will conduct compliance activities on certified payrolls and other DBRA compliance for all DBRA-covered contractors and subcontractors throughout the Project.

(1)PwC will conduct its compliance activities according to the Agreed Upon Procedures (AUP) program, to which all parties have consented. The AUP program can be found in Appendix 2.

(2)All of PwC’s compliance activities costs will be paid for by GPC.

(3)GPC will instruct PwC to perform such compliance activities at such frequency as GPC deems necessary, which shall be no less than once per year during the life of the project.

(4)All parties will be provided with a minimum of two weeks’ notice prior to the commencement of PwC’s compliance activities. Such notice shall include a tentative schedule of activities and initial request for documents.

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Appendix 1(a)

DBA Cover Letter to CLA Subcontractors

Contractor Letterhead

----- DRAFT -----

[DATE]

[contact name]

[Contractor or Subcontractor]

[Address]

[City, ST Zip]

RE: Davis-Bacon and Related Acts Compliance for Contractors Subject to the CLA

Vogtle Units 3 & 4 Project

Dear [Contractor or Subcontractor Contact Name]:

You have been hired to [insert description of work] on the Vogtle Units 3 & 4 Project (“Project”) located in Burke County, Georgia (“site”). Georgia Power Company (“GPC”) and the other owners of the Project are in the process of being awarded a loan guarantee for the Project through the Department of Energy (“DOE”). One condition to receive the loan guarantee is that all contractors and subcontractors who perform construction work at the site must comply with the Davis-Bacon Act and Related Acts (collectively, “DBRA”) as implemented through Sec. 1702(k) of the Energy Policy Act of 2005.. As a contractor who will perform construction work, it is important for your organization to understand that you will be required to comply with all the requirements of the DBRA. You will be required to fully comply with all DBRA requirements from the date of closing on the loan guarantee forward. As a contractor who will perform construction work on this Project, you will also be subject to the Nuclear Power Construction Labor Agreement (CLA). The CLA is one of the collective bargaining agreements among the various contractors and labor unions that will perform construction work on the Project.

This correspondence is intended to provide you with a summary of DBRA requirements, CLA requirements, and references so that additional information about DBRA and associated standards can be obtained. Enclosed with this letter are the following documents:

1. Davis-Bacon and Related Acts Compliance: An Outline of What Your Organization Must Do to Meet Its Responsibilities;

2. Davis-Bacon Act Required Contract Language (to be inserted in all subcontracts);

3. Wage Determinations for Burke County, GA (Heavy Construction, Building Construction, and Highway Construction).

By sending this information, we are not intending to provide legal advice. In addition to DBRA and CLA requirements, you are expected to comply with all Federal and State employment and other applicable laws. For example, the recordkeeping requirements of DBRA summarized, herein, are, in addition to, the recordkeeping requirements that cover your employees under the Fair Labor Standards Act (FLSA). Other employment laws that may apply include Title VII of the Civil Rights Act of 1964, the Americans With Disabilities Act, the Age Discrimination Employment Act, Executive Order 11246, the Family Medical Leave Act, and E*Verify requirements contained in Executive Order 12989. For a complete explanation and advice of the applicability of Federal and State law, we recommend you discuss with your legal counsel.

The Davis-Bacon and Related Acts

The Davis-Bacon Act ("DBA") requires all contractors and subcontractors performing services on federally-assisted contracts to pay their laborers and mechanics (employees performing construction and related work) not less than the prevailing wage rates and fringe benefits listed for the job classifications identified in the applicable current DBA Area Wage Determination (AWD). It is important to keep in mind, that the DBA labor standards clauses included in your contract must be included in any contract you enter into with another organization to perform work at the site of this Project.

The Copeland “Anti-Kickback” Act prohibits contractors, from, in any way, inducing an employee to give up any part of their compensation, and requires contractors to submit a weekly statement of the wages paid to each employee performing DBRA covered work. (www.dol.gov/whd/regs/statutes/copeland.htm)

You must pay all employees weekly, and your organization, as the employer, must submit weekly-certified payroll records electronically using eMars, a web-based service that allows users to easily enter, certify, sign, and submit their certified payrolls pursuant to DBRA.

Once the loan guarantee agreement is executed by GPC and DOE, as an employer performing work covered by the labor standards of the DBRA, you must post the WH-1321 “Employee Rights Under the Davis-Bacon Act” poster at the site of the work, in a location where your employees may easily see it. Your organization must also post the AWDs. (www.dol.gov/whd/programs/dbra/wh1321.htm) Please note that the DBRA and AWD are in addition to other Federal and State required postings.¹

Payroll and basic records for all laborers and mechanics (all the job classifications identified in the AWD) employed by you at the site, must be maintained during the work, and for three years after completion of the Project. Records that must be maintained include:

_________________________

¹ Posting requirements under eight Federal laws (Title VII, ADEA, ADA, EPA, E.O. 11246, GINA, §503 of the Rehabilitation Act of 1973, and VEVRAA) are combined into the single "Equal Employment Opportunity is THE LAW" Poster, a copy of which is available on the Department of Labor's website at http://www.dol.gove/ofccp/regs/compliance/posters/pdf/eeopost.pdf. The combined poster does not cover other Federal posting requirements under USERRA, FLSA, FMLA, NLRA Rights under Executive Order 13496, E-Verify (two posting requirements), EPPA, OSHA, or postings required by the State of Georgia.

◦ Name, address and Social Security number of each employee,

◦ Each employee’s work classification(s),

◦ Hourly rates of pay, including the rates of contributions or costs anticipated for fringe benefits or their cash equivalents,

◦ Daily and weekly numbers of hours worked,

◦ Deductions made,

◦ Actual wages paid,

◦ If applicable, detailed information regarding various fringe benefit programs, including records that show that the program has been communicated in writing to the laborers and the mechanics affected,

◦ If applicable, detailed information regarding approved apprenticeship or trainee programs.

You organization must, on a weekly basis, submit an electronic certified payroll through the eMars system. You must also electronically certify a “Statement of Compliance” and electronically sign the certified payroll through eMars. Submission of weekly payrolls must be completed and submitted within seven days after the regular pay date for the pay period.

GPC has hired PricewaterhouseCoopers (PwC) to conduct monitoring and compliance activities on certified payrolls and other DBRA compliance for all contractors and subcontractors throughout the Project. You must cooperate fully with PwC during their compliance activities.

In the future, you may also be asked to submit, via survey or otherwise, wage data and other information to the Wage and Hour Division (“WHD”) of the U.S. Department of Labor (“DOL”). [Contractor Name] encourages your organization to fully cooperate with the WHD and other divisions of DOL.

If a contractor disregards its obligations to its employees or the DOL in violation of the DBRA, that organization may be subject to contract termination and debarment from future federal or federally assisted contracts for up to three years. In the event of actual or suspected violations, contract payments may be withheld in sufficient amounts to satisfy actual or potential liabilities for unpaid wages that result from violations of DBRA.

Once DBRA requirements are imposed as a result of the loan guarantee agreement, falsification of certified payroll records or the kickback of wages in violation of the Copeland “Anti-Kickback” Act may subject your organization to civil or criminal prosecution resulting in fines and/or imprisonment.

The Nuclear Power Construction Labor Agreement versus the DBRA

The CLA is one of the collective bargaining agreements among the various contractors and labor unions that will perform construction work on the Project. The CLA sets forth applicable hourly wages and benefits for each union craft. It also provides the terms and conditions of working on the Project, including but not limited to, safety issues, hours of work, shifts, attendance policy, no strike policy, and grievance procedures. As a contractor on this Project, you must comply with the terms and conditions set forth in the CLA.

Both the DBRA and the CLA apply to construction workers, both exempt certain executives, and both require you to pay workers weekly. However, there are instances where the DBRA and the CLA impose different obligations. One important area where the DBRA and the CLA may impose different obligations is the wage rates and fringe benefits. If the wage rate and/ or fringe benefits for a job classification or craft are different between the DBRA and the CLA, you should pay the higher wage rate and/or fringe benefits.

Furthermore, the CLA limits its applicability to the site outlined in Appendix B. If construction work is performed outside this area that fits within the DBRA’s definition of site of work (see the attached Compliance Outline Section 3.2 and see 29 C.F.R. § 5.2(l)), then you must still comply with the DBRA for this work, even though it may be exempt from the CLA. The CLA also has some additional overtime and shift requirements that the DBRA does not require; you should comply with these CLA requirements.

Finally, there may be some differences with regards to apprentices and helpers on this Project. Both the DBRA and the CLA allow a certain ratio of apprentices to journeymen on this Project; to the extent these ratios differ, you must keep your ratio within the lower ratio. The DBRA only permits apprentices who are registered in a bona fide apprentice program that is recognized by the DOL; to the extent the CLA might allow other “apprentices” to work under it, apprentices that are not recognized under the DBRA are not permitted to work and be paid as apprentices on this Project. The CLA also allows for helpers, pre-apprentices, and/or sub-journeymen; the DBRA only allows “helpers” if a helper is listed as a separate job classification on the wage determination. On the current versions of the DBRA wage determinations which are attached hereto, there are no helper classifications; therefore, at this time, no helpers, pre-apprentices, or sub-journeymen may be paid under these classifications on this Project.

Concluding Thoughts

[Contractor Name] expects and requires absolute compliance by your organization with all DBRA and CLA requirements. Irrespective of DOE or DOL action, violations may result in the termination of your contract. To facilitate compliance, we have prepared the attached “Davis-Bacon and Related Acts Compliance: An Outline of What Your Organization Must Do to Meet Its Responsibilities.” Should you have questions regarding compliance, please do not hesitate to contact the undersigned. We are here to assist you in fully complying with these requirements.

In addition, the DOL provides employers with easy-to-access information on DBRA compliance, including the DBRA Forms (http://www.dol.gov/whd/programs/dbra/forms.htm). Other compliance assistance includes the Davis-Bacon and Related Acts (“DBRA”) Web page (http://www.dol.gov/whd/programs/dbra/index.htm) and regulatory and interpretive materials available on the Compliance Assistance “By Laws" (http://www.dol.gov/compliance/laws/comp-

dbra.htm) web page. DOE’s Desk Guide may also be helpful (though some portions, such as those relating to CWHSSA, do not apply to this project. (http://www1.eere.energy.gov/wip/pdfs/doe_dba_desk_guide.pdf)

Should you have any questions concerning your organization’s DBRA obligations or our attached DBRA Compliance Outline, please call me.

Sincerely,

[name]

DBA Compliance Specialist

[phone]

[email]

Enclosures

Appendix 1(b)

DBA Cover Letter to Non-CLA Subcontractors

Contractor Letterhead

----- DRAFT -----

[DATE]

[contact name]

[Contractor or Subcontractor]

[Address]

[City, ST Zip]

RE:    Davis-Bacon and Related Acts Compliance

Vogtle Units 3 & 4 Project

Dear [Contractor or Subcontractor Contact Name]:

You have been hired to [insert description of work] on the Vogtle Units 3 & 4 Project (“Project”) located in Burke County, Georgia (“site”). Georgia Power Company (“GPC”) and the other owners of the Project are in the process of being awarded a loan guarantee for the Project through the Department of Energy (“DOE”). One condition to receive the loan guarantee is that all contractors and subcontractors who perform construction work at the site must comply with the Davis-Bacon Act and Related Acts (collectively, “DBRA”), as implemented through Sec. 1702(k) of the Energy Policy Act of 2005.. As a contractor who will perform construction work, it is important for your organization to understand that you will be required to comply with all the requirements of the DBRA. You will be required to fully comply with all DBRA requirements from the date of closing on the loan guarantee forward.

This correspondence is intended to provide you with a summary of DBRA requirements and references so that additional information about DBRA and associated standards can be obtained. Enclosed with this letter are the following documents:

1. Davis-Bacon and Related Acts Compliance: An Outline of What Your Organization Must Do to Meet Its Responsibilities;

2. Davis-Bacon Act Required Contract Language (to be inserted in all subcontracts);

3. Wage Determinations for Burke County, GA (Heavy Construction, Building Construction, and Highway Construction).

By sending this information, we are not intending to provide legal advice. In addition to DBRA requirements, you are expected to comply with all Federal and State employment and other applicable laws. For example, the recordkeeping requirements of DBRA summarized, herein,

are, in addition to, the recordkeeping requirements that cover your employees under the Fair Labor Standards Act (FLSA). Other employment laws that may apply include Title VII of the Civil Rights Act of 1964, the Americans With Disabilities Act, the Age Discrimination Employment Act, Executive Order 11246, the Family Medical Leave Act, and E*Verify requirements contained in Executive Order 12989. For a complete explanation and advice of the applicability of Federal and State law, we recommend you discuss with your legal counsel.

The Davis-Bacon and Related Acts

The Davis-Bacon Act ("DBA") requires all contractors and subcontractors performing services on federally-assisted contracts to pay their laborers and mechanics (employees performing construction and related work) not less than the prevailing wage rates and fringe benefits listed for the job classifications identified in the applicable current DBA Area Wage Determination (AWD). It is important to keep in mind, that the DBA labor standards clauses included in your contract must be included in any contract you enter into with another organization to perform work at the site of this Project.

The Copeland “Anti-Kickback” Act prohibits contractors, from, in any way, inducing an employee to give up any part of their compensation, and requires contractors to submit a weekly statement of the wages paid to each employee performing DBRA covered work. (www.dol.gov/whd/regs/statutes/copeland.htm)

You must pay all employees weekly, and your organization, as the employer, must submit weekly-certified payroll records electronically using eMars, a web-based service that allows users to easily enter, certify, sign, and submit their certified payrolls pursuant to DBRA.

Once the loan guarantee agreement is executed by GPC and DOE, as an employer performing work covered by the labor standards of the DBRA, you must post the WH-1321 “Employee Rights Under the Davis-Bacon Act” poster at the site of the work, in a location where your employees may easily see it. Your organization must also post the AWDs. (www.dol.gov/whd/programs/dbra/wh1321.htm) Please note that the DBRA and AWD are in addition to other Federal and State required postings.¹

Payroll and basic records for all laborers and mechanics (all the job classifications identified in the AWD) employed by you at the site, must be maintained during the work, and for three years after completion of the Project. Records that must be maintained include:

◦ Name, address and Social Security number of each employee,

◦ Each employee’s work classification(s),

_______________________________

¹ Posting requirements under eight Federal laws (Title VII, ADEA, ADA, EPA, E.O. 11246, GINA, §503 of the Rehabilitation Act of 1973, and VEVRAA) are combined into the single "Equal Employment Opportunity is THE LAW" Poster, a copy of which is available on the Department of Labor's website at http://www.dol.gove/ofccp/regs/compliance/posters/pdf/eeopost.pdf. The combined poster does not cover other Federal posting requirements under USERRA, FLSA, FMLA, NLRA Rights under Executive Order 13496, E-Verify (two posting requirements), EPPA, OSHA, or postings required by the State of Georgia.

◦ Hourly rates of pay, including the rates of contributions or costs anticipated for fringe benefits or their cash equivalents,

◦ Daily and weekly numbers of hours worked,

◦ Deductions made,

◦ Actual wages paid,

◦ If applicable, detailed information regarding various fringe benefit programs, including records that show that the program has been communicated in writing to the laborers and the mechanics affected,

◦ If applicable, detailed information regarding approved apprenticeship or trainee programs.

You organization must, on a weekly basis, submit an electronic certified payroll through the eMars system. You must also electronically certify a “Statement of Compliance” and electronically sign the certified payroll through eMars. Submission of weekly payrolls must be completed and submitted within seven days after the regular pay date for the pay period.

GPC has hired PricewaterhouseCoopers (PwC) to conduct monitoring and compliance activities on certified payrolls and other DBRA compliance for all contractors and subcontractors throughout the Project. You must cooperate fully with PwC during their compliance activities.

In the future, you may also be asked to submit, via survey or otherwise, wage data and other information to the Wage and Hour Division (“WHD”) of the U.S. Department of Labor (“DOL”). [Contractor Name] encourages your organization to fully cooperate with the WHD and other divisions of DOL.

If a contractor disregards its obligations to its employees or the DOL in violation of the DBRA, that organization may be subject to contract termination and debarment from future federal or federally assisted contracts for up to three years. In the event of actual or suspected violations, contract payments may be withheld in sufficient amounts to satisfy actual or potential liabilities for unpaid wages that result from violations of DBRA.

Once DBRA requirements are imposed as a result of the loan guarantee agreement, falsification of certified payroll records or the kickback of wages in violation of the Copeland “Anti-Kickback” Act may subject your organization to civil or criminal prosecution resulting in fines and/or imprisonment.

Concluding Thoughts

[Contractor Name] expects and requires absolute compliance by your organization with all DBRA requirements. Irrespective of DOE or DOL action, violations may result in the

termination of your contract. To facilitate compliance, we have prepared the attached “Davis-Bacon and Related Acts Compliance: An Outline of What Your Organization Must Do to Meet Its Responsibilities.” Should you have questions regarding compliance, please do not hesitate to contact the undersigned. We are here to assist you in fully complying with these requirements.

In addition, the DOL provides employers with easy-to-access information on DBRA compliance, including the DBRA Forms (http://www.dol.gov/whd/programs/dbra/forms.htm). Other compliance assistance includes the Davis-Bacon and Related Acts (“DBRA”) Web page (http://www.dol.gov/whd/programs/dbra/index.htm) and regulatory and interpretive materials available on the Compliance Assistance “By Laws" (http://www.dol.gov/compliance/laws/comp-dbra.htm) web page. DOE’s Desk Guide may also be helpful (though some portions, such as those relating to CWHSSA, do not apply to this project. (http://www1.eere.energy.gov/wip/pdfs/doe_dba_desk_guide.pdf)

Should you have any questions concerning your organization’s DBRA obligations or our attached DBRA Compliance Outline, please call me.

Sincerely,

[name]

DBA Compliance Specialist

[phone]

[email]

Enclosures

Appendix 1(c)

Required DBA Contract Language

Davis-Bacon Act Required Contract Clauses

SECTION (a) MINIMUM WAGES, ETC.

(1) Minimum wages.

(i) All laborers and mechanics employed or working upon the site of the work (or under the United States Housing Act of 1937 or under the Housing Act of 1949 in the construction or development of the project), will be paid unconditionally and not less often than once a week, and without subsequent deduction or rebate on any account (except such payroll deductions as are permitted by regulations issued by the Secretary of Labor under the Copeland Act (29 CFR part 3)), the full amount of wages and bona fide fringe benefits (or cash equivalents thereof) due at time of payment computed at rates not less than those contained in the wage determination of the Secretary of Labor which is attached hereto and made a part hereof, regardless of any contractual relationship which may be alleged to exist between the contractor and such laborers and mechanics.

Contributions made or costs reasonably anticipated for bona fide fringe benefits under section 1(b)(2) of the Davis-Bacon Act on behalf of laborers or mechanics are considered wages paid to such laborers or mechanics, subject to the provisions of paragraph (a)(1)(iv) of this section; also, regular contributions made or costs incurred for more than a weekly period (but not less often than quarterly) under plans, funds, or programs which cover the particular weekly period, are deemed to be constructively made or incurred during such weekly period. Such laborers and mechanics shall be paid the appropriate wage rate and fringe benefits on the wage determination for the classification of work actually performed, without regard to skill, except as provided in Sec. 5.5(a)(4) [paragraph (a)(4) below]. Laborers or mechanics performing work in more than one classification may be compensated at the rate specified for each classification for the time actually worked therein: Provided, That the employer's payroll records accurately set forth the time spent in each classification in which work is performed. The wage determination (including any additional classification and wage rates conformed under paragraph (a)(1)(ii) of this section) and the Davis-Bacon poster (WH-1321) shall be posted at all times by the contractor and its subcontractors at the site of the work in a prominent and accessible place where it can be easily seen by the workers.

(ii)(A) The contracting officer shall require that any class of laborers or mechanics, including helpers, which is not listed in the wage determination and which is to be employed under the contract shall be classified in conformance with the wage determination. The contracting officer shall approve an additional classification and wage rate and fringe benefits therefore only when the following criteria have been met:

(1) The work to be performed by the classification requested is not performed by a classification in the wage determination; and

(2) The classification is utilized in the area by the construction industry; and

(3) The proposed wage rate, including any bona fide fringe benefits, bears a reasonable relationship to the wage rates contained in the wage determination.

(ii)(B) If the contractor and the laborers and mechanics to be employed in the classification (if known), or their representatives, and the contracting officer agree on the classification and wage rate (including the amount designated for fringe benefits where appropriate), a report of the action taken shall be sent by the contracting officer to the Administrator of the Wage and Hour Division, Employment Standards Administration, U.S. Department of Labor, Washington, DC 20210. The Administrator, or an authorized representative, will approve, modify, or disapprove every additional classification action within 30 days of receipt and so advise the contracting officer or will notify the contracting officer within the 30-day period that additional time is necessary.

(ii)(C) In the event the contractor, the laborers or mechanics to be employed in the classification or their representatives, and the contracting officer do not agree on the proposed classification and wage rate (including the amount designated for fringe benefits, where appropriate), the contracting officer shall refer the questions, including the views of all interested parties and the recommendation of the contracting officer, to the Administrator for determination. The Administrator, or an authorized representative, will issue a determination within 30 days of receipt and so advise the contracting officer or will notify the contracting officer within the 30-day period that additional time is necessary.

(ii)(D) The wage rate (including fringe benefits where appropriate) determined pursuant to paragraphs (a)(1)(ii) (B) or (C) of this section, shall be paid to all workers performing work in the classification under this contract from the first day on which work is performed in the classification.

(iii) Whenever the minimum wage rate prescribed in the contract for a class of laborers or mechanics includes a fringe benefit which is not expressed as an hourly rate, the contractor shall either pay the benefit as stated in the wage determination or shall pay another bona fide fringe benefit or an hourly cash equivalent thereof.

(iv) If the contractor does not make payments to a trustee or other third person, the contractor may consider as part of the wages of any laborer or mechanic the amount of any costs reasonably anticipated in providing bona fide fringe benefits under a plan or program, Provided, That the Secretary of Labor has found, upon the written request of the contractor, that the applicable standards of the Davis-Bacon Act have been met. The Secretary of Labor may require the contractor to set aside in a separate account assets for the meeting of obligations under the plan or program.

(2) Withholding.

The Department of Energy ("DOE") shall upon its own action or upon written request of an authorized representative of the Department of Labor withhold or cause to be withheld from the contractor under this contract or any other Federal contract with the same prime contractor, or any other federally-assisted contract subject to Davis-Bacon prevailing wage requirements, which is held by the same prime contractor, so much of the accrued payments or advances as may be considered necessary to pay laborers and mechanics, including apprentices, trainees, and helpers, employed by the contractor or any subcontractor the full amount of wages required by the contract. In the event of failure to pay any laborer or mechanic, including any apprentice, trainee, or helper, employed or working on the site of the work (or under the United States Housing Act of 1937 or under the Housing Act of 1949 in the construction or development of the project), all or part of the wages required by the contract, DOE may, after written notice to the contractor, sponsor, applicant, or owner, take such action as may be necessary to cause the suspension of any further payment, advance, or guarantee of funds until such violations have ceased.

(3) Payrolls and basic records.

(i) Payrolls and basic records relating thereto shall be maintained by the contractor during the course of the work and preserved for a period of three years thereafter for all laborers and mechanics working at the site of the work (or under the United States Housing Act of 1937, or under the Housing Act of 1949, in the construction or development of the project). Such records shall contain the name, address, and social security number of each such worker, his or her correct classification, hourly rates of wages paid (including rates of contributions or costs anticipated for bona fide fringe benefits or cash equivalents thereof of the types described in section 1(b)(2)(B) of the Davis-Bacon Act), daily and weekly number of hours worked, deductions made and actual wages paid. Whenever the Secretary of Labor has found under 29 CFR 5.5(a)(1)(iv) that the wages of any laborer or mechanic include the amount of any costs reasonably anticipated in providing benefits under a plan or program described in section 1(b)(2)(B) of the Davis-Bacon Act, the contractor shall maintain records which show that the commitment to provide such benefits is enforceable, that the plan or program is financially responsible, and that the plan or program has been communicated in writing to the laborers or mechanics affected, and records which show the costs anticipated or the actual cost incurred in providing such benefits. Contractors employing apprentices or trainees under approved programs shall maintain written evidence of the registration of apprenticeship programs and certification of trainee programs, the registration of the apprentices and trainees, and the ratios and wage rates prescribed in the applicable programs.

(ii)(A) The contractor shall submit weekly for each week in which any contract work is performed a copy of all payrolls to the DOE) if the agency is a party to the contract, but if the agency is not such a party, the contractor will submit the payrolls to the applicant, sponsor, or owner, as the case may be, for transmission to DOE. The payrolls submitted shall set out accurately and completely all of the information required to be maintained under 29 CFR 5.5(a)(3)(i), except that full social security numbers and home addresses shall not be included on weekly transmittals. Instead the payrolls shall only need to include an individually identifying number for each employee (e.g., the last four digits of the employee's social security number). The required weekly payroll information may be submitted in any form desired. Optional Form WH-347 is available for this purpose from the Wage and Hour Division Web site at http://www.dol.gov/esa/whd/forms/wh347instr.htm or its successor site. The prime contractor is responsible for the submission of copies of payrolls by all subcontractors. Contractors and subcontractors shall maintain the full social security number and current address of each covered worker, and shall provide them upon request to DOE if the agency is a party to the contract, but if the agency is not such a party, the contractor will submit them to the applicant, sponsor, or owner, as the case may be, for transmission to DOE, the contractor, or the Wage and Hour Division of the Department of Labor for purposes of an investigation or audit of compliance with prevailing wage requirements. It is not a violation of this section for a prime contractor to require a subcontractor to provide addresses and social security numbers to the prime contractor for its own records, without weekly submission to the sponsoring government agency (or the applicant, sponsor, or owner).

(ii)(B) Each payroll submitted shall be accompanied by a ``Statement of Compliance,'' signed by the contractor or subcontractor or his or her agent who pays or supervises the payment of the persons employed under the contract and shall certify the following:

(1) That the payroll for the payroll period contains the information required to be provided under Sec. 5.5 (a)(3)(ii) of Regulations, 29 CFR part 5, the appropriate information is being maintained under Sec. 5.5 (a)(3)(i) of Regulations, 29 CFR part 5, and that such information is correct and complete;

(2) That each laborer or mechanic (including each helper, apprentice, and trainee) employed on the contract during the payroll period has been paid the full weekly wages earned, without rebate, either directly or indirectly, and that no deductions have been made either directly or indirectly from the full wages earned, other than permissible deductions as set forth in Regulations, 29 CFR part 3;

(3) That each laborer or mechanic has been paid not less than the applicable wage rates and fringe benefits or cash equivalents for the classification of work performed, as specified in the applicable wage determination incorporated into the contract.

(ii)(C) The weekly submission of a properly executed certification set forth on the reverse side of Optional Form WH-347 shall satisfy the requirement for submission of the ``Statement of Compliance'' required by paragraph (a)(3)(ii)(B) of this section.

(ii)(D) The falsification of any of the above certifications may subject the contractor or subcontractor to civil or criminal prosecution under section 1001 of title 18 and section 231 of title 31 of the United States Code.

(iii) The contractor or subcontractor shall make the records required under paragraph (a)(3)(i) of this section available for inspection, copying, or transcription by authorized representatives of DOE or the Department of Labor, and shall permit such representatives to interview employees during working hours on the job. If the contractor or subcontractor fails to submit the required records or to make them available, the Federal agency may, after written notice to the contractor, sponsor, applicant, or owner, take such action as may be necessary to cause the suspension of any further payment, advance, or guarantee of funds. Furthermore, failure to submit the required records upon request or to make such records available may be grounds for debarment action pursuant to 29 CFR 5.12.

(4) Apprentices and trainees

(i) Apprentices. Apprentices will be permitted to work at less than the predetermined rate for the work they performed when they are employed pursuant to and individually registered in a bona fide apprenticeship program registered with the U.S. Department of Labor, Employment and Training Administration, Office of Apprenticeship Training, Employer and Labor Services, or with a State Apprenticeship Agency recognized by the Office, or if a person is employed in his or her first 90 days of probationary employment as an apprentice in such an apprenticeship program, who is not individually registered in the program, but who has been certified by the Office of Apprenticeship Training, Employer and Labor Services or a State Apprenticeship Agency (where appropriate) to be eligible for probationary employment as an apprentice. The allowable ratio of apprentices to journeymen on the job site in any craft classification shall not be greater than the ratio permitted to the contractor as to the entire work force under the registered program. Any worker listed on a payroll at an apprentice wage rate, who is not registered or otherwise employed as stated above, shall be paid not less than the applicable wage rate on the wage determination for the classification of work actually performed. In addition, any apprentice performing work on the job site in excess of the ratio permitted under the registered program shall be paid not less than the applicable wage rate on the wage determination for the work actually performed. Where a contractor is performing construction on a project in a locality other than that in which its program is registered, the ratios and wage rates (expressed in percentages of the journeyman's hourly rate) specified in the contractor's or subcontractor's registered program shall be observed. Every apprentice must be paid at not less than the rate specified in the registered program for the apprentice's level of progress, expressed as a percentage of the journeymen hourly rate specified in the applicable wage determination. Apprentices shall be paid fringe benefits in accordance

with the provisions of the apprenticeship program. If the apprenticeship program does not specify fringe benefits, apprentices must be paid the full amount of fringe benefits listed on the wage determination for the applicable classification. If the Administrator determines that a different practice prevails for the applicable apprentice classification, fringes shall be paid in accordance with that determination. In the event the Office of Apprenticeship Training, Employer and Labor Services, or a State Apprenticeship Agency recognized by the Office, withdraws approval of an apprenticeship program, the contractor will no longer be permitted to utilize apprentices at less than the applicable predetermined rate for the work performed until an acceptable program is approved.

(ii) Trainees. Except as provided in 29 CFR 5.16, trainees will not be permitted to work at less than the predetermined rate for the work performed unless they are employed pursuant to and individually registered in a program which has received prior approval, evidenced by formal certification by the U.S. Department of Labor, Employment and Training Administration. The ratio of trainees to journeymen on the job site shall not be greater than permitted under the plan approved by the Employment and Training Administration. Every trainee must be paid at not less than the rate specified in the approved program for the trainee's level of progress, expressed as a percentage of the journeyman hourly rate specified in the applicable wage determination. Trainees shall be paid fringe benefits in accordance with the provisions of the trainee program. If the trainee program does not mention fringe benefits, trainees shall be paid the full amount of fringe benefits listed on the wage determination unless the Administrator of the Wage and Hour Division determines that there is an apprenticeship program associated with the corresponding journeyman wage rate on the wage determination which provides for less than full fringe benefits for apprentices. Any employee listed on the payroll at a trainee rate who is not registered and participating in a training plan approved by the Employment and Training Administration shall be paid not less than the applicable wage rate on the wage determination for the classification of work actually performed. In addition, any trainee performing work on the job site in excess of the ratio permitted under the registered program shall be paid not less than the applicable wage rate on the wage determination for the work actually performed. In the event the Employment and Training Administration withdraws approval of a training program, the contractor will no longer be permitted to utilize trainees at less than the applicable predetermined rate for the work performed until an acceptable program is approved.

(iii) Equal employment opportunity. The utilization of apprentices, trainees and journeymen under this part shall be in conformity with the equal employment opportunity requirements of Executive Order 11246, as amended, and 29 CFR part 30.

(5) Compliance with Copeland Act requirements.

The contractor shall comply with the requirements of 29 CFR part 3, which are incorporated by reference in this contract.

(6) Subcontracts.

The contractor or subcontractor shall insert in any subcontracts the clauses contained in 29 CFR 5.5(a)(1) through (10) and such other clauses as DOE may by appropriate instructions require, and also a clause requiring the subcontractors to include these clauses in any lower tier subcontracts. The prime contractor shall be responsible for the compliance by any subcontractor or lower tier subcontractor with all the contract clauses in 29 CFR 5.5.

(7) Contract termination: debarment.

A breach of the contract clauses in 29 CFR 5.5 may be grounds for termination of the contract, and for debarment as a contractor and a subcontractor as provided in 29 CFR 5.12.

(8) Compliance with Davis-Bacon and Related Act requirements.

All rulings and interpretations of the Davis-Bacon and Related Acts contained in 29 CFR parts 1, 3, and 5 are herein incorporated by reference in this contract.

(9) Disputes concerning labor standards.

Disputes arising out of the labor standards provisions of this contract shall not be subject to the general disputes clause of this contract. Such disputes shall be resolved in accordance with the procedures of the Department of Labor set forth in 29 CFR parts 5, 6, and 7. Disputes within the meaning of this clause include disputes between the contractor (or any of its subcontractors) and the contracting agency, the U.S. Department of Labor, or the employees or their representatives.

(10) Certification of eligibility.

(i) By entering into this contract, the contractor certifies that neither it (nor he or she) nor any person or firm who has an interest in the contractor's firm is a person or firm ineligible to be awarded Government contracts by virtue of section 3(a) of the Davis-Bacon Act or 29 CFR 5.12(a)(1).

(ii) No part of this contract shall be subcontracted to any person or firm ineligible for award of a Government contract by virtue of section 3(a) of the Davis-Bacon Act or 29 CFR 5.12(a)(1).

(iii) The penalty for making false statements is prescribed in the U.S. Criminal Code, 18 U.S.C. 1001.”

Appendix 1(d)

DBRA Compliance Outline for CLA Contractors

Davis-Bacon and Related Acts Compliance

For Contractors Subject to The CLA

An Outline of What Your Organization Must Do to Meet Its Responsibilities

1. Contract Requirements

1.1 The Contract that you entered into to perform work on the Vogtle Units 3 & 4 Project (“Project”) located in Burke County, Georgia requires that you comply with each of the following Federal statutes:

1.1.1 The Davis-Bacon Act (DBA), 40 U.S.C. § 3141 et seq., as implemented through Sec. 1702(k) of the Energy Policy Act of 2005;

1.1.1.1 The DBA requires payment of locally prevailing wages and fringe benefits, as defined in the applicable wage determination, to laborers and mechanics employed for construction, alteration, or repair (including painting and decorating) on this Project.

1.1.2 The Copeland “Anti-Kickback” Act, 40 U.S.C. § 3145 and 18 U.S.C. § 874;

1.1.2.1. The Anti-Kickback Act prohibits the “kickbacks” of wages and back wages and requires contractors to submit a weekly Statement of Compliance.

1.1.3 Together, these Federal Statutes are known as the Davis-Bacon and Related Acts (DBRA).

1.2 This document will outline your compliance obligations under each of these Acts, but you remain responsible for reading, reviewing, and understanding each of the Acts.

1.3 This document will not address any obligations under the Fair Labor Standards Act (FLSA) or any applicable state laws. You remain responsible for your compliance with any other applicable laws.

2. Subcontract Provisions

2.1. The provisions of 29 C.F.R. § 5.5 and the Wage Determinations must be included any subcontract that you enter into.

2.1.1. These provisions are attached as an Exhibit to your Contract.

2.2. You are responsible for ensuring that any subcontractor that you hire to perform work covered by the DBA complies with the DBRA and all of the provisions contained in this document.

3. Workers Covered

3.1. Laborers and Mechanics

3.1.1. The DBA applies to “laborers and mechanics.”

3.1.2. The term “laborer and mechanic” includes those workers whose duties are manual or physical in nature (including those workers who use tools or who are performing the work of a trade), as distinguished from mental or managerial duties.

3.1.2.1. This term includes:

3.1.2.1.1. Apprentices;

3.1.2.1.2. Trainees;

3.1.2.1.3. Helpers;

3.1.2.1.4. Non-exempt working foremen who devote more than 20 percent of their time during a workweek to mechanic or laborer duties;

3.1.2.2. This terms does NOT include:

3.1.2.2.1. Workers whose duties are primarily administrative, executive, or clerical, rather than manual;

3.1.2.2.2. Timekeepers, inspectors, architects, or engineers;

3.1.2.2.3. Persons employed in a bona fide executive, administrative, or professional capacity.

3.1.3. Under the DBA, the concept of “laborers and mechanics” as “independent contractors” does not exist, except as set forth in Section 3.3.3, which addresses Bona-fide owner-operators of trucks. This includes owner-operators of construction equipment such as backhoes, bulldozers, and cranes. All such persons must receive DBA wages and fringe benefits.

3.2. Site of the Work

3.2.1. The DBA applies to laborers and mechanics employed “directly upon the site of the work.”

3.2.2. “Site of the work” is the physical place or places where the building or work called for in the contract will remain, and any other site where a significant portion of the building or work is constructed, provided that such site is established specifically for the performance of the contract or project.

3.2.2.1. Batch plants, borrow pits, job headquarters, tool yards, etc., are part of the “site”, provided they are dedicated exclusively, or nearly so, to the contract or project, and are adjacent or virtually adjacent to the site of the work.

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3.2.2.2. Not included in the “site of work” are permanent home offices, branch plant establishments, fabrication plants, tool yards, etc., of a contractor or subcontractor whose location and continuance in operation are determined wholly without regard to a particular federal or federally assisted project.

3.2.3. On this Project, the site of work includes, but is not limited to: the entire Vogtle Units 3 & 4 site and all related components, parts, and areas; the reactors; the turbines; the generator; the control room; any offices; any maintenance sheds; the concrete batch plant; the transmission lines; etc.

3.2.4. The DBA applies to all laborers and mechanics employed by a contractor or subcontractor on the site of the work.

3.3. Truck Drivers

3.3.1. Truck drivers are covered by the DBA in the following circumstances:

3.3.1.1. Drivers of a contractor or subcontractor for time spent working on the site of the work;

3.3.1.2. Drivers of a contractor or subcontractor for time spent loading and/or unloading materials and supplies on the site of the work, if such time is not de minimis;

3.3.1.3. Truck drivers transporting materials or supplies between a facility that is deemed part of the site of the work and the actual construction site;

3.3.1.4. Truck drivers transporting portion(s) of the building or work between a site established specifically for the performance of the contract or project where a significant portion of such building or work is constructed and the physical place(s) where the building or work called for in the contract(s) will remain.

3.3.2. Truck drivers are NOT covered in the following instances:

3.3.2.1. Material delivery truck drivers while off “the site of the work”;

3.3.2.2. Drivers of a contractor or subcontractor traveling between a Davis-Bacon job and a commercial supply facility while they are off the “site of the work”;

3.3.2.3. Truck drivers whose time spent on the site of the work is de minimis, such as only a few minutes at a time merely to pick up or drop off materials or supplies.

3.3.3. Bona-fide owner-operators of trucks are also not covered by the DBA. An owner-operator of a truck is a person who owns and drives his own truck. On your Certified Payrolls, include the names of any owner-operators and put the notation “owner-operator” instead of filling in the hours worked or the rates paid.

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3.3.3.1. Note: This owner-operator exception does NOT apply to owner-operators of other equipment such as bulldozers, cranes, etc. See Section 3.1.4.

3.4. Materialmen

3.4.1. Workers who manufacture or furnish materials, supplies, or equipment generally are NOT covered by the DBA.

3.4.2. The delivery of such materials, supplies, or equipment to the site of work also generally is NOT covered by the DBA.

3.4.3. However, if an employee of a manufacturer or a material supplier performs more than an incidental amount of construction work in any workweek at the site of work, then that employee will be covered by the DBA for that workweek.

3.4.3.1. Construction work includes adjustments to and installation of the materials, supplies, or equipment at the site of work.

3.4.3.2. More than an incidental amount of construction work means more than 20% of the worker’s time during that workweek.

3.4.3.2.1. Therefore, if an employee of a manufacturer or a material supplier spends more than 8 hours in any given week installing, altering, or repairing materials, supplies, or equipment at the site of work, then that employee is covered by the DBA for that week and must be paid DBA wages and fringe benefits.

3.4.4. You are responsible for ensuring that any manufacturer or material supplier from whom you purchase materials, supplies, or equipment who performs more than an incidental amount of construction work in any workweek at the site of work, complies with the DBRA and all of the provisions contained in this document.

3.5. Apprentices / Trainees

3.5.1. Apprentices are those persons employed and individually registered in a bona fide apprenticeship program registered with the U.S. Department of Labor, Employment and Training Administration (ETA), Office of Apprenticeship (OA), or with a state apprenticeship agency recognized by ETA.

3.5.2. Trainees are persons registered and receiving on-the-job training in a construction occupation under a program approved in advance by the U.S. Department of Labor, Employment and Training Administration, as meeting its standards for on-the-job training programs and which has been so certified by that administration.

3.5.3. Apprentices and trainees are laborers and mechanics but are not listed on a wage determination.

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3.5.4. Apprentices and trainees may be used on this Project and paid less than the specified rate for the work performed if the apprentice or trainee is individually registered in an approved apprenticeship or training program.

3.5.5. The apprentices/trainees must be paid the percentage (%) of the basic hourly rate required or fringe benefits specified in the approved apprenticeship program and in accordance with their level of progression.

3.5.6. The contractor is limited in the number of apprentices/trainees permitted on the job site based on the allowable ratio of apprentices/ trainees to journeymen specified in the approved program.

3.6. Helpers

3.6.1. A distinct classification of “helper” will be issued in DBA wage determinations only where all of the following conditions are met:

3.6.1.1. The duties of the helper are clearly defined and distinct from those of any other classification on the wage determination;

3.6.1.2. The use of such helpers is an established prevailing practice in the area; and

3.6.1.3. The helper is not employed as a trainee in an informal training program.

3.6.2. Helpers may be employed on a DBA/DBRA covered construction project only if the helper classification is listed in the Davis-Bacon wage determination in the contract or the classification is added with approval by DOL. Helper classes are issued or approved only where they are within the scope of the definition stated above.

3.7. Exemptions and Exclusions

3.7.1. Certain workers employed by contractors or subcontractors may be exempt or excluded from the DBA. You are responsible for determining if any such exemptions or exclusions apply for your own workers and those employed by your subcontractors. Any questions about DBA applicability should be directed to the SCS DBA Compliance Liaison.

3.7.2. To reiterate, some of the applicable exemptions and exclusions include:

3.7.2.1. Workers whose duties are primarily administrative, executive, or clerical, rather than manual;

3.7.2.2. Timekeepers, inspectors, architects, or engineers;

3.7.2.3. Persons employed in a bona fide executive, administrative, or professional capacity;

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3.7.2.4. Workers who are not employed at the “site of work.”

4. Job Classifications

4.1. Determining the Applicable Job Classification

4.1.1. Once you have determined that an employee is a “laborer or mechanic” who is employed “directly upon the site of the work,” you must determine that employee’s job classification.

4.1.2. A list of the job classifications currently applicable to this Project is contained in the Wage Determination.

4.1.2.1. The Wage Determination is attached as an Exhibit to your Contract.

4.1.2.2. The Wage Determinations are for three categories of construction: building, heavy, and highway.

4.1.2.2.1. The Building Wage Determination should be used for any construction involving an enclosed structure with walk-in access for the purpose of housing persons, machinery, equipment, or supplies.

4.1.2.2.2. The Heavy Construction Wage Determination should be used for everything else.

4.1.2.2.3. It is not anticipated that the Highway Construction Wage Determination will be utilized. However, should road construction become necessary, the Highway Construction Wage Determination is available for use.

4.1.2.2.4. You may use job classifications from more than one Wage Determination where appropriate.

4.1.3. If the laborer or mechanic’s job is covered by the Nuclear Power Construction Labor Agreement (CLA), you should refer to the scope of work sections in the various craft agreements to determine the applicable CLA craft.

4.1.3.1. You should then refer to the Craft-to-DBA Job Classification Matrix and select the job classification on the Wage Determination that corresponds to the CLA craft.

4.1.4. If a laborer or mechanic’s job is not covered by the CLA, then you should select the job classification from the Wage Determination that best describes the duties that the laborer or mechanic performs.

4.1.4.1. The duties which an employee actually performs govern the classification and the rate of pay to which the employee is entitled under the applicable wage determination, as in accordance with area practice.

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4.1.4.2. To fall within a particular job classification, an employee need not perform all of the duties listed. It is sufficient that the duties performed are within the scope of the listed classification.

4.1.4.3. Note: Some employees may perform work in more than one job classification. You will need to record the time spent in each job classification and allocate the time accordingly.

4.1.4.4. If you are still not certain which job classification one or more of your employees fits into, please contact the SCS DBA Compliance Specialist for assistance.

4.2. Additional Classifications

4.2.1. If you have one or more employees who will be performing unique or specialized work that cannot be properly classified in any of the job classifications in the Wage Determination, then please contact the SCS DBA Compliance Specialist for assistance.

4.2.2. At the time you contact the SCS DBA Compliance Specialist, you will need to submit, in writing, a detailed description of the work to be performed along with a proposed wage rate, including fringe benefits.

4.2.3. The SCS DBA Compliance Specialist will work with the Southern Company Services Employee Relations/General Counsel organization, which will decide whether or not to submit a request for an additional classification to the DOL

4.2.4. Any additional classification submitted to the DOL will only be approved if:

4.2.4.1. The work to be performed by the classification requested is not performed by a classification in the wage determination; and

4.2.4.2. The classification is utilized in the area by the construction industry; and

4.2.4.3. The proposed wage rate, including any bona fide fringe benefits, bears a reasonable relationship to the wage rates contained in the wage determination.

5. Wages

5.1. Wage Determination

5.1.1. The DBA requires payment of locally prevailing wages and fringe benefits to laborers and mechanics.

5.1.2. The locally prevailing wages and fringe benefits are set forth in the Wage Determination.

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5.1.2.1. After you identify the applicable job classification for each employee, you must pay at least the minimum wage rate and the fringe benefits associated with each employee’s job classification on the Wage Determination.

5.1.2.2. If the employee works in more than one job classification, you must record the time spent in each job classification and allocate the time accordingly. You must pay the employee at least the minimum wage rate and fringe benefits associated with each job classification.

5.1.3. Prevailing Wages include:

5.1.2.1. The basic hourly rate;

5.1.2.2. Contractor contributions irrevocably made to a trustee or third party pursuant to a bona fide fringe benefit fund, plan, or program; and

5.1.2.3. The rate of costs the contractor reasonably anticipates in providing bona fide fringe benefits where certain conditions are met.

5.1.4. You must pay your employees weekly.

5.2. Fringe Benefits

5.2.1. You can satisfy your obligation to pay fringe benefits by:

5.2.1.1. paying the basic hourly rate and fringe benefits in cash;

5.2.1.2. contributing payments to a bona fide plan; or

5.2.1.3. any combination of the two.

5.2.1.3.1. This means that if the wage rate is $10.00 with $1.00 in fringe benefits, you can pay $11.00 in cash, pay $10.00 in cash and provide $1.00 in fringe benefits, or pay $9.00 in cash and provide $2.00 in fringe benefits.

5.2.2. Fringe benefits must be paid weekly for all hours worked - both straight time and overtime hours.

5.2.2.1. However, the amount of fringe benefits may be excluded from the calculation of the overtime rate under the Fair Labor Standards Act (“FLSA”).

5.2.2.2. For example, if a wage rate is $10.00 per hour plus $1.00 in fringe benefits, the overtime rate would be $16.00 ($10.00 * 1.5 = $15.00 + $1.00 fringe).

5.2.3. Fringe benefits include:

5.2.3.1. Life insurance;

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5.2.3.2. Health insurance;

5.2.3.3. Pension;

5.2.3.4. Vacation;

5.2.3.5. Holiday;

5.2.3.6. Sick Leave.

5.2.4. Fringe benefits do NOT include:

5.2.4.1. the use of a truck;

5.2.4.2. a Thanksgiving turkey;

5.2.4.3. a Christmas bonus;

5.2.4.4. any benefit required by federal, state, or local law, such as:

5.2.4.4.1. workers compensation;

5.2.4.4.2. unemployment compensation;

5.2.4.4.3. social security contributions.

5.2.5. You may take credit for bona fide fringe benefit fund contributions made to third party trustees or insurers that:

5.2.5.1. are irrevocably paid; and

5.2.5.2. are made regularly, not less often than quarterly.

5.2.5.2.1. Examples include paying monthly health insurance premiums or quarterly contributions to a retirement plan trust.

5.2.5.2.2. A pension plan that meets the Employment Retirement Income Security Act (ERISA) requirements may be considered “bona fide” for DBA/DBRA purposes.

5.2.6. An unfunded fringe benefit plan is a plan where the benefits will be paid from the general assets of the contractor and include: holiday plans, vacation plans, and sick pay plans.

5.2.6.1. No type of fringe benefit is eligible for consideration as an unfunded plan unless it meets the following criteria:

5.2.6.1.1. It can be reasonably anticipated to provide benefits described in the Davis-Bacon Act;

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5.2.6.1.2. It represents a commitment that can be legally enforced;

5.2.6.1.3. It is carried out under a financially responsible plan or program; and

5.2.6.1.4. The plan or program has been communicated in writing to the laborers and mechanics affected.

5.2.6.1.5. The contractor has requested written permission from DOL pursuant to 29 CFR 5.5(a)(1)(iv) to seek credit for such costs under DBRA.

5.2.7. For a benefit that the contractor pays annually (such as some health insurance, pension plans, etc.), you determine the hourly rate of contribution that is creditable towards the DBA fringe benefit requirement by:

5.2.7.1. dividing the total annual contributions by the total annual hours worked (both DBA and non-DBA work); then

5.2.7.2. allocate the fringe benefit credits so that DBA work is not being used to fund benefits on private (non-DBA) work.

5.3. Overtime

5.3.1. The FLSA requires the payment of time and one-half the basic rate of pay for all hours worked in excess of 40 hours in a week.

5.3.2. The basic rate of pay under DBA and the FLSA is the straight time hourly rate and can not be less than the basic hourly rate required in an applicable wage determination.

5.3.2.1. The amount of fringe benefits paid are excluded in computing overtime obligations.

5.3.3. If an employee works in more than one job classification with different basic rates of pay, the overtime pay may be computed based on the weekly average rate (or “regular rate”) - the total straight time pay for work (at all such rates) during the week, divided by the total number of hours worked at all jobs worked in the workweek.

5.3.3.1. For example, if the employee worked 30 hours during a week in a job where the wage rate is $10.00 per hour plus $3.00 in fringe benefits, and 18 hours during a week in a job where the wage rate is $12.00 per hour plus $2.50 in fringe benefits, the regular rate used to calculate overtime is:

5.3.3.1.1. Step 1: Determine the straight time wages due - excluding fringe benefits

30 hours at the rate of $10.00	= $300.00
18 hours at the rate of $12.00	= $216.00
Total straight time wages	= $516.00

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5.3.3.1.2. Step 2: Calculate the “regular rate”

($516.00 / 48 hours worked) = $10.75 “regular rate”

5.3.3.1.3 Step 3: Compute the overtime premium due

½($10.75) x 8 overtime hours worked = $43.00

6. Certified Payrolls

6.1. Submitting Weekly Certified Payrolls

6.1.1. You must electronically complete, sign, and submit a certified payroll each week through eMars, a web-based service that allows users to submit certified payrolls pursuant to DBRA.

6.1.2. You must submit the certified payroll through eMars within seven days after the pay day for the weekly pay period.

6.1.3. Detailed instructions concerning the preparation of the payroll:

6.1.3.1. Name of Contractor or Subcontractor: Fill in your firm's name and check appropriate box.

6.1.3.2. Address: Fill in your firm's address.

6.1.3.3. Payroll No.: Beginning with the number "1", list the payroll number for the submission.

6.1.3.4. For Week Ending: List the workweek ending date.

6.1.3.5. Project and Location: List the name of the project and the location.

6.1.3.6. Project or Contract No.: Fill in the number for the project or contract.

6.1.3.7. Name and Individual Identifying Number of Worker: Enter each worker's full name and the last four digits of worker's social security number on each weekly payroll submitted.

6.1.3.7.1. Do NOT list the worker’s entire social security number.

6.1.3.8. Work Classifications: List the job classification from the Wage Determination that is descriptive of work actually performed by each laborer or mechanic.

6.1.3.8.1. If an individual worked in more than one job classification in that workweek, use separate entries (e.g., two lines) for each job classification to show an accurate breakdown of hours worked in each job.

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6.1.3.9. Day and Date; Hours Worked Each Day: List the day (Sunday, Monday, etc.) and date at the top. Then list the amount of straight time (“S”) and overtime (“O”) hours worked in the applicable boxes.

6.1.3.9.1. Enter all hours worked in excess of 40 hours a week as "overtime".

6.1.3.10. Total Hours: Fill in the total number of hours worked that week.

6.1.3.11. Rate of Pay: In the "straight time" box for each worker, list the actual hourly rate paid for straight time worked, plus cash paid in lieu of fringe benefits paid. When recording the straight time hourly rate, any cash paid in lieu of fringe benefits may be shown separately from the basic rate. For example, "$12.25/.40" would reflect a $12.25 base hourly rate plus $0.40 for fringe benefits. This is of assistance in correctly computing overtime. See "Fringe Benefits" below. When overtime is worked, show the overtime hourly rate paid plus any cash in lieu of fringe benefits paid in the "overtime" box for each worker; otherwise, you may skip this box. See "Fringe Benefits" below. Payment of not less than time and one-half the basic or regular rate paid is required for overtime. In addition to paying no less than the predetermined rate for the classification which an individual works, the contractor must pay amounts predetermined as fringe benefits in the wage decision made part of the contract to approved fringe benefit plans, funds or programs or shall pay as cash in lieu of fringe benefits. See "FRINGE BENEFITS" below.

6.1.3.12. Gross Amount Earned: Enter gross amount earned this week on this project. If part of a worker's weekly wage was earned on projects other than the project described on this payroll, enter in column 7 first the amount earned on the Federal or Federally assisted project and then the gross amount earned during the week on all projects, thus "$163.00/$420.00" would reflect the earnings of a worker who earned $163.00 on a Federally assisted construction project during a week in which $420.00 was earned on all work.

6.1.3.13. Deductions: Columns are provided for showing deductions made. If more deductions than columns provided are involved, use the available columns and show the balance of deductions under "Other" column; show actual total under "Total Deductions" column; and in the attachment to the payroll describe the deduction(s) contained in the "Other" column. All deductions must be in accordance with the provisions of the Copeland Act Regulations, 29 C.F.R., Part 3. If an individual worked on other jobs in addition to this project, show actual deductions from his/her weekly gross wage, and indicate that deductions are based on his gross wages.

6.1.3.14. Net Wages Paid for Week: Fill in the amount of net wages paid to the worker (this must match the amount on the worker’s paycheck).

6.1.3.15. Certification: The Certification is located on page 2 of the Form. Someone with knowledge that the facts represented are true should sign this

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statement. While the "statement of compliance" need not be notarized, the statement is subject to the penalties provided by 18 U.S.C. § 1001, namely, a fine, possible imprisonment of not more than 5 years, or both.

6.1.3.16. Items 1 and 2: Space has been provided between items (1) and (2) of the statement for describing any deductions made. If all deductions made are adequately described in the "Deductions" column above, state "See Deductions column in this payroll." See "FRINGE BENEFITS" below for instructions concerning filling out paragraph 4 of the statement.

6.1.3.17. Item 4(a) - WHERE FRINGE BENEFITS ARE PAID TO APPROVED PLANS, FUNDS, OR PROGRAMS: If paying all fringe benefits to approved plans, funds, or programs in amounts not less than were determined in the applicable wage decision of the Secretary of Labor, show the basic cash hourly rate and overtime rate paid to each worker on the face of the payroll and check paragraph 4(a) of the statement on page 2 of the WH-347 payroll form to indicate the payment. Note any exceptions in section 4(c).

6.1.3.18. Item 4(b) - WHERE FRINGE BENEFITS ARE PAID IN CASH: If not paying all fringe benefits to approved plans, funds, or programs in amounts of at least those that were determined in the applicable wage decision of the Secretary of Labor, pay any remaining fringe benefit amount to each laborer and mechanic and insert in the "straight time" of the "Rate of Pay" column of the payroll an amount not less than the predetermined rate for each classification plus the amount of fringe benefits determined for each classification in the applicable wage decision. Inasmuch as it is not necessary to pay time and a half on cash paid in lieu of fringe benefits, the overtime rate shall be not less than the sum of the basic predetermined rate, plus the half time premium on basic or regular rate, plus the required cash in lieu of fringe benefits at the straight time rate. In addition, check paragraph 4(b) of the statement on page 2 of the payroll form to indicate the payment of fringe benefits in cash directly to the workers. Note any exceptions in section 4(c).

6.1.3.19. Item 4(c) - Exceptions: Any contractor who is making payment to approved plans, funds, or programs in amounts less than the wage determination requires is obliged to pay the deficiency directly to the covered worker as cash in lieu of fringe benefits. Enter any exceptions to section 4(a) or 4(b) in section 4(c). Enter in the Exception column the craft, and enter in the Explanation column the hourly amount paid each worker as cash in lieu of fringe benefits and the hourly amount paid to plans, funds, or programs as fringe benefits. The contractor must pay an amount not less than the predetermined rate plus cash in lieu of fringe benefits as shown in section 4(c) to each such individual for all hours worked (unless otherwise provided by applicable wage determination) on the Federal or Federally assisted project. Enter the rate paid and amount of cash paid in lieu of fringe benefits per hour in column 6 on the payroll. See paragraph on "Contractors where fringe benefits are paid in cash" for computation of overtime rate.

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6.2. Errors

6.2.1. If, after you have submitted a Certified Payroll through eMars, you receive an error message, you will need to correct the error.

6.2.1.1. You will need to submit a revised Certified Payroll through eMars.

6.2.1.2. You will also need to pay all employees the full amount of back wages that they are due.

6.2.1.2.1. You must keep all documentation of any supplemental payment.

6.2.1.2.2. You must submit a revised Certified Payroll through eMars and keep a copy of the documentation of any payment.

7. Record Keeping Requirements

7.1. You must keep payroll and basic records for all laborers and mechanics for three years after completion of the Project.

7.2. Records that must be maintained include:

7.2.1. Full Name, address, and complete Social Security number of each employee;

7.2.2. Each employee’s job classification(s);

7.2.3. Hourly rates of pay;

7.2.4. Amount of fringe benefits - either the amounts of contributions to benefit plan or the cash equivalent;

7.2.5. Daily and weekly number of hours worked;

7.2.6. Deductions made;

7.2.7. Actual wages paid (copies of check stubs);

7.2.8. If applicable, detailed information regarding various fringe benefit programs, including records that show that the program has been communicated in writing to the laborers and mechanics;

7.2.9. If applicable, detailed information regarding approved apprentice and training programs.

7.3. Keep a copy of each Certified Payroll submitted.

8. Posting Requirements

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8.1. You must post the following posters at the site of the work, in a location where it may be easily seen by your employees:

8.1.1. WH-1321 “Employee Rights Under the Davis-Bacon Act”;

8.1.2. the Wage Determination;

8.1.3. NLRB Rights poster;

8.1.4. Federal “5 in 1” poster (EEO, FLSA, OSHA, USERRA, and polygraph);

8.1.5. Georgia Workers’ Compensation poster;

8.1.6. Internal worker concerns process memorandum.

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Appendix 1(e)

DBRA Compliance Outline for Non-CLA Contractors

Davis-Bacon and Related Acts Compliance

An Outline of What Your Organization Must Do to Meet Its Responsibilities

1. Contract Requirements

1.1. The Contract that you entered into to perform work on the Vogtle Units 3 & 4 Project (“Project”) located in Burke County, Georgia requires that you comply with each of the following Federal statutes:

1.1.1. The Davis-Bacon Act (DBA), 40 U.S.C. § 3141 et seq., as implemented through Sec. 1702(k) of the Energy Policy Act of 2005;

1.1.1.1. The DBA requires payment of locally prevailing wages and fringe benefits, as defined in the applicable wage determination, to laborers and mechanics employed for construction, alteration, or repair (including painting and decorating) on this Project.

1.1.2. The Copeland “Anti-Kickback” Act, 40 U.S.C. § 3145 and 18 U.S.C. § 874;

1.1.2.1. The Anti-Kickback Act prohibits the “kickbacks” of wages and back wages and requires contractors to submit a weekly Statement of Compliance.

1.1.3. Together, these Federal Statutes are known as the Davis-Bacon and Related Acts (DBRA).

1.2. This document will outline your compliance obligations under each of these Acts, but you remain responsible for reading, reviewing, and understanding each of the Acts.

1.3. This document will not address any obligations under the Fair Labor Standards Act (FLSA) or any applicable state laws. You remain responsible for your compliance with any other applicable laws.

2. Subcontract Provisions

2.1. The provisions of 29 C.F.R. § 5.5 and the Wage Determinations must be included any subcontract that you enter into.

2.1.1. These provisions are attached as an Exhibit to your Contract.

2.2. You are responsible for ensuring that any subcontractor that you hire to perform work covered by the DBA complies with the DBRA and all of the provisions contained in this document.

3. Workers Covered

3.1. Laborers and Mechanics

3.1.1. The DBA applies to “laborers and mechanics.”

3.1.2. The term “laborer and mechanic” includes those workers whose duties are manual or physical in nature (including those workers who use tools or who are performing the work of a trade), as distinguished from mental or managerial duties.

3.1.2.1. This term includes:

3.1.2.1.1. Apprentices;

3.1.2.1.2. Trainees;

3.1.2.1.3. Helpers;

3.1.2.1.4. Non-exempt working foremen who devote more than 20 percent of their time during a workweek to mechanic or laborer duties;

3.1.2.2. This terms does NOT include:

3.1.2.2.1. Workers whose duties are primarily administrative, executive, or clerical, rather than manual;

3.1.2.2.2. Timekeepers, inspectors, architects, or engineers;

3.1.2.2.3. Persons employed in a bona fide executive, administrative, or professional capacity.

3.1.3. Under the DBA, the concept of “laborers and mechanics” as “independent contractors” does not exist, except as set forth in Section 3.3.3, which addresses Bona-fide owner-operators of trucks. This includes owner-operators of construction equipment such as backhoes, bulldozers, and cranes. All such persons must receive DBA wages and fringe benefits.

3.2. Site of the Work

3.2.1. The DBA applies to laborers and mechanics employed “directly upon the site of the work.”

3.2.2. “Site of the work” is the physical place or places where the building or work called for in the contract will remain, and any other site where a significant portion of the building or work is constructed, provided that such site is established specifically for the performance of the contract or project.

3.2.2.1. Batch plants, borrow pits, job headquarters, tool yards, etc., are part of the “site”, provided they are dedicated exclusively, or nearly so, to the contract or project, and are adjacent or virtually adjacent to the site of the work.

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3.2.2.2. Not included in the “site of work” are permanent home offices, branch plant establishments, fabrication plants, tool yards, etc., of a contractor or subcontractor whose location and continuance in operation are determined wholly without regard to a particular federal or federally assisted project.

3.2.3. On this Project, the site of work includes, but is not limited to: the entire Vogtle Units 3 & 4 site and all related components, parts, and areas; the reactors; the turbines; the generator; the control room; any offices; any maintenance sheds; the concrete batch plant; the transmission lines; etc.

3.2.4. The DBA applies to all laborers and mechanics employed by a contractor or subcontractor on the site of the work.

3.3. Truck Drivers

3.3.1. Truck drivers are covered by the DBA in the following circumstances:

3.3.1.1. Drivers of a contractor or subcontractor for time spent working on the site of the work;

3.3.1.2. Drivers of a contractor or subcontractor for time spent loading and/or unloading materials and supplies on the site of the work, if such time is not de minimis;

3.3.1.3. Truck drivers transporting materials or supplies between a facility that is deemed part of the site of the work and the actual construction site;

3.3.1.4. Truck drivers transporting portion(s) of the building or work between a site established specifically for the performance of the contract or project where a significant portion of such building or work is constructed and the physical place(s) where the building or work called for in the contract(s) will remain.

3.3.2. Truck drivers are NOT covered in the following instances:

3.3.2.1. Material delivery truck drivers while off “the site of the work”;

3.3.2.2. Drivers of a contractor or subcontractor traveling between a Davis-Bacon job and a commercial supply facility while they are off the “site of the work”;

3.3.2.3. Truck drivers whose time spent on the site of the work is de minimis, such as only a few minutes at a time merely to pick up or drop off materials or supplies.

3.3.3. Bona-fide owner-operators of trucks are also not covered by the DBA. An owner-operator of a truck is a person who owns and drives his own truck. On your Certified Payrolls, include the names of any owner-operators and put the notation “owner-operator” instead of filling in the hours worked or the rates paid.

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3.3.3.1. Note: This owner-operator exception does NOT apply to owner-operators of other equipment such as bulldozers, cranes, etc. See Section 3.1.4.

3.4. Materialmen

3.4.1. Workers who manufacture or furnish materials, supplies, or equipment generally are NOT covered by the DBA.

3.4.2. The delivery of such materials, supplies, or equipment to the site of work also generally is NOT covered by the DBA.

3.4.3. However, if an employee of a manufacturer or a material supplier performs more than an incidental amount of construction work in any workweek at the site of work, then that employee will be covered by the DBA for that workweek.

3.4.3.1. Construction work includes adjustments to and installation of the materials, supplies, or equipment at the site of work.

3.4.3.2. More than an incidental amount of construction work means more than 20% of the worker’s time during that workweek.

3.4.3.2.1. Therefore, if an employee of a manufacturer or a material supplier spends more than 8 hours in any given week installing, altering, or repairing materials, supplies, or equipment at the site of work, then that employee is covered by the DBA for that week and must be paid DBA wages and fringe benefits.

3.4.4. You are responsible for ensuring that any manufacturer or material supplier from whom you purchase materials, supplies, or equipment who performs more than an incidental amount of construction work in any workweek at the site of work, complies with the DBRA and all of the provisions contained in this document.

3.5. Apprentices / Trainees

3.5.1. Apprentices are those persons employed and individually registered in a bona fide apprenticeship program registered with the U.S. Department of Labor, Employment and Training Administration (ETA), Office of Apprenticeship (OA), or with a state apprenticeship agency recognized by ETA.

3.5.2. Trainees are persons registered and receiving on-the-job training in a construction occupation under a program approved in advance by the U.S. Department of Labor, Employment and Training Administration, as meeting its standards for on-the-job training programs and which has been so certified by that administration.

3.5.3. Apprentices and trainees are laborers and mechanics but are not listed on a wage determination.

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3.5.4. Apprentices and trainees may be used on this Project and paid less than the specified rate for the work performed if the apprentice or trainee is individually registered in an approved apprenticeship or training program.

3.5.5. The apprentices/trainees must be paid the percentage (%) of the basic hourly rate required or fringe benefits specified in the approved apprenticeship program and in accordance with their level of progression.

3.5.6. The contractor is limited in the number of apprentices/trainees permitted on the job site based on the allowable ratio of apprentices/ trainees to journeymen specified in the approved program.

3.6. Helpers

3.6.1. A distinct classification of “helper” will be issued in DBA wage determinations only where all of the following conditions are met:

3.6.1.1. The duties of the helper are clearly defined and distinct from those of any other classification on the wage determination;

3.6.1.2. The use of such helpers is an established prevailing practice in the area; and

3.6.1.3. The helper is not employed as a trainee in an informal training program.

3.6.2. Helpers may be employed on a DBA/DBRA covered construction project only if the helper classification is listed in the Davis-Bacon wage determination in the contract or the classification is added with approval by DOL. Helper classes are issued or approved only where they are within the scope of the definition stated above.

3.7. Exemptions and Exclusions

3.7.1. Certain workers employed by contractors or subcontractors may be exempt or excluded from the DBA. You are responsible for determining if any such exemptions or exclusions apply for your own workers and those employed by your subcontractors. Any questions about DBA applicability should be directed to the SCS DBA Compliance Liaison.

3.7.2. To reiterate, some of the applicable exemptions and exclusions include:

3.7.2.1. Workers whose duties are primarily administrative, executive, or clerical, rather than manual;

3.7.2.2. Timekeepers, inspectors, architects, or engineers;

3.7.2.3. Persons employed in a bona fide executive, administrative, or professional capacity;

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3.7.2.4. Workers who are not employed at the “site of work.”

4. Job Classifications

4.1. Determining the Applicable Job Classification

4.1.1. Once you have determined that an employee is a “laborer or mechanic” who is employed “directly upon the site of the work,” you must determine that employee’s job classification.

4.1.2. A list of the job classifications currently applicable to this Project is contained in the Wage Determination.

4.1.2.1. The Wage Determination is attached as an Exhibit to your Contract.

4.1.2.2. The Wage Determinations are for three categories of construction: building, heavy, and highway.

4.1.2.2.1. The Building Wage Determination should be used for any construction involving an enclosed structure with walk-in access for the purpose of housing persons, machinery, equipment, or supplies.

4.1.2.2.2. The Heavy Construction Wage Determination should be used for everything else.

4.1.2.2.3. It is not anticipated that the Highway Construction Wage Determination will be utilized. However, should road construction become necessary, the Highway Construction Wage Determination is available for use.

4.1.2.2.4. You may use job classifications from more than one Wage Determination where appropriate.

4.1.3. Select the job classification from the Wage Determination that best describes the duties that the laborer or mechanic performs.

4.1.3.1. The duties which an employee actually performs govern the classification and the rate of pay to which the employee is entitled under the applicable wage determination.

4.1.3.2. To fall within a particular job classification, an employee need not perform all of the duties listed. It is sufficient that the duties performed are within the scope of the listed classification.

4.1.3.3. Note: Some employees may perform work in more than one job classification. You will need to record the time spent in each job classification and allocate the time accordingly.

4.1.3.4. If you are still not certain which job classification one or more of your employees fits into, please contact the SCS DBA Compliance Specialist for assistance.

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4.2. Additional Classifications

4.2.1. If you have one or more employees who will be performing unique or specialized work that cannot be properly classified in any of the job classifications in the Wage Determination, then please contact the SCS DBA Compliance Specialist for assistance.

4.2.2. At the time you contact the SCS DBA Compliance Specialist, you will need to submit, in writing, a detailed description of the work to be performed along with a proposed wage rate, including fringe benefits.

4.2.3. The SCS DBA Compliance Specialist will work with the Southern Company Services Employee Relations/General Counsel organization, which will decide whether or not to submit a request for an additional classification to the DOL

4.2.4. Any additional classification submitted to the DOL will only be approved if:

4.2.4.1. The work to be performed by the classification requested is not performed by a classification in the wage determination; and

4.2.4.2. The classification is utilized in the area by the construction industry; and

4.2.4.3. The proposed wage rate, including any bona fide fringe benefits, bears a reasonable relationship to the wage rates contained in the wage determination.

5. Wages

5.1. Wage Determination

5.1.1. The DBA requires payment of locally prevailing wages and fringe benefits to laborers and mechanics.

5.1.2. The locally prevailing wages and fringe benefits are set forth in the Wage Determination.

5.1.2.1. After you identify the applicable job classification for each employee, you must pay at least the minimum wage rate and the fringe benefits associated with each employee’s job classification on the Wage Determination.

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5.1.2.2. If the employee works in more than one job classification, you must record the time spent in each job classification and allocate the time accordingly. You must pay the employee at least the minimum wage rate the fringe benefits associated with each job classification.

5.1.3. Prevailing Wages include:

5.1.3.1. The basic hourly rate;

5.1.3.2. Contractor contributions irrevocably made to a trustee or third party pursuant to a bona fide fringe benefit fund, plan, or program; and

5.1.3.3. The rate of costs the contractor reasonably anticipates in providing bona fide fringe benefits where certain conditions are met.

5.1.4. You must pay your employees weekly.

5.2. Fringe Benefits

5.2.1. You can satisfy your obligation to pay fringe benefits by:

5.2.1.1. paying the basic hourly rate and fringe benefits in cash;

5.2.1.2. contributing payments to a bona fide plan; or

5.2.1.3. any combination of the two.

5.2.1.3.1. This means that if the wage rate is $10.00 with $1.00 in fringe benefits, you can pay $11.00 in cash, pay $10.00 in cash and provide $1.00 in fringe benefits, or pay $9.00 in cash and provide $2.00 in fringe benefits.

5.2.2. Fringe benefits must be paid weekly for all hours worked - both straight time and overtime hours.

5.2.2.1. However, the amount of fringe benefits may be excluded from the calculation of the overtime rate under the Fair Labor Standards Act (“FLSA”).

5.2.2.2. For example, if a wage rate is $10.00 per hour plus $1.00 in fringe benefits, the overtime rate would be $16.00 ($10.00 * 1.5 = $15.00 + $1.00 fringe).

5.2.3. Fringe benefits include:

5.2.3.1. Life insurance;

5.2.3.2. Health insurance;

5.2.3.3. Pension;

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5.2.3.4. Vacation;

5.2.3.5. Holiday;

5.2.3.6. Sick Leave.

5.2.4. Fringe benefits do NOT include:

5.2.4.1. the use of a truck;

5.2.4.2. a Thanksgiving turkey;

5.2.4.3. a Christmas bonus;

5.2.4.4. any benefit required by federal, state, or local law, such as:

5.2.4.4.1. workers compensation;

5.2.4.4.2. unemployment compensation;

5.2.4.4.3. social security contributions.

5.2.5. You may take credit for bona fide fringe benefit fund contributions made to third party trustees or insurers that:

5.2.5.1. are irrevocably paid; and

5.2.5.2. are made regularly, not less often than quarterly.

5.2.5.2.1. Examples include paying monthly health insurance premiums or quarterly contributions to a retirement plan trust.

5.2.5.2.2. A pension plan that meets the Employment Retirement Income Security Act (ERISA) requirements may be considered “bona fide” for DBA/DBRA purposes.

5.2.6. An unfunded fringe benefit plan is a plan where the benefits will be paid from the general assets of the contractor and include: holiday plans, vacation plans, and sick pay plans.

5.2.6.1. No type of fringe benefit is eligible for consideration as an unfunded plan unless it meets the following criteria:

5.2.6.1.1. It can be reasonably anticipated to provide benefits described in the Davis-Bacon Act;

5.2.6.1.2. It represents a commitment that can be legally enforced;

5.2.6.1.3. It is carried out under a financially responsible plan or program; and

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5.2.6.1.4. The plan or program has been communicated in writing to the laborers and mechanics affected.

5.2.6.1.5. The contractor has requested written permission from DOL pursuant to 29 CFR 5.5(a)(1)(iv) to seek credit for such costs under DBRA.

5.2.7. For a benefit that the contractor pays annually (such as some health insurance, pension plans, etc.), you determine the hourly rate of contribution that is creditable towards the DBA fringe benefit requirement by:

5.2.7.1. dividing the total annual contributions by the total annual hours worked (both DBA and non-DBA work); then

5.2.7.2. allocate the fringe benefit credits so that DBA work is not being used to fund benefits on private (non-DBA) work.

5.3. Overtime

5.3.1. The FLSA requires the payment of time and one-half the basic rate of pay for all hours worked in excess of 40 hours in a week.

5.3.2. The basic rate of pay under DBA and the FLSA is the straight time hourly rate and can not be less than the basic hourly rate required in an applicable wage determination.

5.3.2.1. The amount of fringe benefits paid are excluded in computing overtime obligations.

5.3.3. If an employee works in more than one job classification with different basic rates of pay, the overtime pay may be computed based on the weekly average rate (or “regular rate”) - the total straight time pay for work (at all such rates) during the week, divided by the total number of hours worked at all jobs worked in the workweek.

5.3.3.1. For example, if the employee worked 30 hours during a week in a job where the wage rate is $10.00 per hour plus $3.00 in fringe benefits, and 18 hours during a week in a job where the wage rate is $12.00 per hour plus $2.50 in fringe benefits, the regular rate used to calculate overtime is:

5.3.3.1.1. Step 1: Determine the straight time wages due - excluding fringe benefits

30 hours at the rate of $10.00	= $300.00
18 hours at the rate of $12.00	= $216.00
Total straight time wages	= $516.00

5.3.3.1.2.    Step 2: Calculate the “regular rate”

($516.00 / 48 hours worked) = $10.75 “regular rate”

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5.3.3.1.3. Step 3: Compute the overtime premium due

½($10.75) x 8 overtime hours worked = $43.00

6. Certified Payrolls

6.1. Submitting Weekly Certified Payrolls

6.1.1. You must electronically complete, sign, and submit a certified payroll each week through eMars, a web-based service that allows users to submit certified payrolls pursuant to DBRA.

6.1.2. You must submit the certified payroll through eMars within seven days after the pay day for the weekly pay period.

6.1.3. Detailed instructions concerning the preparation of the payroll:

6.1.3.1. Name of Contractor or Subcontractor: Fill in your firm's name and check appropriate box.

6.1.3.2. Address: Fill in your firm's address.

6.1.3.3. Payroll No.: Beginning with the number "1", list the payroll number for the submission.

6.1.3.4. For Week Ending: List the workweek ending date.

6.1.3.5. Project and Location: List the name of the project and the location.

6.1.3.6. Project or Contract No.: Fill in the number for the project or contract.

6.1.3.7. Name and Individual Identifying Number of Worker: Enter each worker's full name and the last four digits of worker's social security number on each weekly payroll submitted.

6.1.3.7.1. Do NOT list the worker’s entire social security number.

6.1.3.8. Work Classifications: List the job classification from the Wage Determination that is descriptive of work actually performed by each laborer or mechanic.

6.1.3.8.1. If an individual worked in more than one job classification in that workweek, use separate entries (e.g., two lines) for each job classification to show an accurate breakdown of hours worked in each job.

6.1.3.9. Day and Date; Hours Worked Each Day: List the day (Sunday, Monday, etc.) and date at the top. Then list the amount of straight time (“S”) and overtime (“O”) hours worked in the applicable boxes.

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6.1.3.9.1. Enter all hours worked in excess of 40 hours a week as "overtime".

6.1.3.10. Total Hours: Fill in the total number of hours worked that week.

6.1.3.11. Rate of Pay: In the "straight time" box for each worker, list the actual hourly rate paid for straight time worked, plus cash paid in lieu of fringe benefits paid. When recording the straight time hourly rate, any cash paid in lieu of fringe benefits may be shown separately from the basic rate. For example, "$12.25/.40" would reflect a $12.25 base hourly rate plus $0.40 for fringe benefits. This is of assistance in correctly computing overtime. See "Fringe Benefits" below. When overtime is worked, show the overtime hourly rate paid plus any cash in lieu of fringe benefits paid in the "overtime" box for each worker; otherwise, you may skip this box. See "Fringe Benefits" below. Payment of not less than time and one-half the basic or regular rate paid is required for overtime. In addition to paying no less than the predetermined rate for the classification which an individual works, the contractor must pay amounts predetermined as fringe benefits in the wage decision made part of the contract to approved fringe benefit plans, funds or programs or shall pay as cash in lieu of fringe benefits. See "FRINGE BENEFITS" below.

6.1.3.12. Gross Amount Earned: Enter gross amount earned this week on this project. If part of a worker's weekly wage was earned on projects other than the project described on this payroll, enter in column 7 first the amount earned on the Federal or Federally assisted project and then the gross amount earned during the week on all projects, thus "$163.00/$420.00" would reflect the earnings of a worker who earned $163.00 on a Federally assisted construction project during a week in which $420.00 was earned on all work.

6.1.3.13. Deductions: Columns are provided for showing deductions made. If more deductions than columns provided are involved, use the available columns and show the balance of deductions under "Other" column; show actual total under "Total Deductions" column; and in the attachment to the payroll describe the deduction(s) contained in the "Other" column. All deductions must be in accordance with the provisions of the Copeland Act Regulations, 29 C.F.R., Part 3. If an individual worked on other jobs in addition to this project, show actual deductions from his/her weekly gross wage, and indicate that deductions are based on his gross wages.

6.1.3.14. Net Wages Paid for Week: Fill in the amount of net wages paid to the worker (this must match the amount on the worker’s paycheck).

6.1.3.15. Certification: The Certification is located on page 2 of the Form. Someone with knowledge that the facts represented are true should sign this statement. While the "statement of compliance" need not be notarized, the statement is subject to the penalties provided by 18 U.S.C. § 1001, namely, a fine, possible imprisonment of not more than 5 years, or both.

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6.1.3.16. Items 1 and 2: Space has been provided between items (1) and (2) of the statement for describing any deductions made. If all deductions made are adequately described in the "Deductions" column above, state "See Deductions column in this payroll." See "FRINGE BENEFITS" below for instructions concerning filling out paragraph 4 of the statement.

6.1.3.17. Item 4(a) - WHERE FRINGE BENEFITS ARE PAID TO APPROVED PLANS, FUNDS, OR PROGRAMS: If paying all fringe benefits to approved plans, funds, or programs in amounts not less than were determined in the applicable wage decision of the Secretary of Labor, show the basic cash hourly rate and overtime rate paid to each worker on the face of the payroll and check paragraph 4(a) of the statement on page 2 of the WH-347 payroll form to indicate the payment. Note any exceptions in section 4(c).

6.1.3.18. Item 4(b) - WHERE FRINGE BENEFITS ARE PAID IN CASH: If not paying all fringe benefits to approved plans, funds, or programs in amounts of at least those that were determined in the applicable wage decision of the Secretary of Labor, pay any remaining fringe benefit amount to each laborer and mechanic and insert in the "straight time" of the "Rate of Pay" column of the payroll an amount not less than the predetermined rate for each classification plus the amount of fringe benefits determined for each classification in the applicable wage decision. Inasmuch as it is not necessary to pay time and a half on cash paid in lieu of fringe benefits, the overtime rate shall be not less than the sum of the basic predetermined rate, plus the half time premium on basic or regular rate, plus the required cash in lieu of fringe benefits at the straight time rate. In addition, check paragraph 4(b) of the statement on page 2 of the payroll form to indicate the payment of fringe benefits in cash directly to the workers. Note any exceptions in section 4(c).

6.1.3.19. Item 4(c) - Exceptions: Any contractor who is making payment to approved plans, funds, or programs in amounts less than the wage determination requires is obliged to pay the deficiency directly to the covered worker as cash in lieu of fringe benefits. Enter any exceptions to section 4(a) or 4(b) in section 4(c). Enter in the Exception column the craft, and enter in the Explanation column the hourly amount paid each worker as cash in lieu of fringe benefits and the hourly amount paid to plans, funds, or programs as fringe benefits. The contractor must pay an amount not less than the predetermined rate plus cash in lieu of fringe benefits as shown in section 4(c) to each such individual for all hours worked (unless otherwise provided by applicable wage determination) on the Federal or Federally assisted project. Enter the rate paid and amount of cash paid in lieu of fringe benefits per hour in column 6 on the payroll. See paragraph on "Contractors where fringe benefits are paid in cash" for computation of overtime rate.

6.2. Errors

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6.2.1. If, after you have submitted a Certified Payroll through eMars, you receive an error message, you will need to correct the error.

6.2.1.1. You will need to submit a revised Certified Payroll through eMars.

6.2.1.2. You will also need to pay all employees the full amount of back wages that they are due.

6.2.1.2.1. You must keep all documentation of any supplemental payment.

6.2.1.2.2. You must submit a revised Certified Payroll through eMars and keep a copy of the documentation of any payment.

7. Record Keeping Requirements

7.1. You must keep payroll and basic records for all laborers and mechanics for three years after completion of the Project.

7.2. Records that must be maintained include:

7.2.1. Full Name, address, and complete Social Security number of each employee;

7.2.2. Each employee’s job classification(s);

7.2.3. Hourly rates of pay;

7.2.4. Amount of fringe benefits - either the amounts of contributions to benefit plan or the cash equivalent;

7.2.5. Daily and weekly number of hours worked;

7.2.6. Deductions made;

7.2.7. Actual wages paid (copies of check stubs);

7.2.8. If applicable, detailed information regarding various fringe benefit programs, including records that show that the program has been communicated in writing to the laborers and mechanics;

7.2.9. If applicable, detailed information regarding approved apprentice and training programs.

7.3. Keep a copy of each Certified Payroll submitted.

8. Posting Requirements

8.1. You must post the following posters at the site of the work, in a location where it may be easily seen by your employees:

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8.1.1. WH-1321 “Employee Rights Under the Davis-Bacon Act”;

8.1.2. the Wage Determination;

8.1.3. NLRB Rights poster;

8.1.4. Federal “5 in 1” poster (EEO, FLSA, OSHA, USERRA, and polygraph);

8.1.5. Georgia Workers’ Compensation poster;

8.1.6. Internal worker concerns process memorandum.

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Appendix 1(f)

Area Wage Determinations

Appendix 2

PwC Agreed Upon Procedures (AUP)

Procedures to be Performed

1. Davis-Bacon Communication at Site

a. Inquire of project management where Davis-Bacon posters are placed. Physically inspect site where poster is to be posted and note if present

b. Perform inquiries of 40 site employees, to be selected haphazardly from workers on site on date of site visit, on the following questions:

i. They are aware that the project is subject to Davis Bacon.

ii. They have seen the Davis-Bacon poster(s) posted at the site.

(Note selections for 1b and 4e to be performed at same time, procedure is to select at rally points in morning and have site employee answer questions.)

2. Submission and Completion of Weekly Certified Payrolls as Required by Davis-Bacon.

a. Inquire of project management to determine if payroll is paid weekly.

b. Obtain a listing of weekly payrolls from the eMars system and haphazardly select 15 weekly payrolls (one per month plus 3 additional selections which are adjacent to a week selected in the monthly selection)

i. Inspect the certification for evidence the certification was performed and completed timely

ii. Agree total from each weekly payroll to copy of check or wire transfer payment.

c. Haphazardly select 5 individuals within each weekly payroll selected in b and mathematically check the certified payroll by recomputing net pay for 5 individual within each weekly payroll selected in b by 1) recomputing gross pay by multiplying hours worked from the payroll register by pay rate from the payroll register and by deducting all deductions shown for employee gross pay within the payroll register.

d. Inspect that is the WH-347 or similar form, as obtained from the eMars system, for each weekly payroll selected in b. has been filled out completely.

e. Inspect that the Statement of Compliance is signed by the contractor or subcontractor or his or her agent who pays or supervises the payment of the persons employed under the contract, by evidence of signature, whether physical or electronic, on the Statement of Compliance.

f. Obtain listing of prime contractor and sub-contractors used by week. Haphazardly select 5 weeks of payroll listings provided by prime contractor including sub contractors and compare subcontractors contained in the payroll listing obtained to listing of sub-contractors used by week.

3. Obtain the Davis-Bacon wage schedule being utilized for payroll computations and compare the pay rates by labor classification to the Davis-Bacon wage schedule identified in loan guarantee agreement.

4. Labor classification and Wage Rates

a. Haphazardly select 10 employees per payroll cycle tested in (2) above and compare basic hourly wage plus fringe from the certified payroll to the Davis Bacon wage schedule specified in the loan guarantee agreement.

b. Obtain listing of employees and classification for 3 payroll cycles and select 5 employees per classification and compare the payrate, per the certified payroll for employee to the Davis Bacon wage schedule specified in the loan guarantee agreement.

c. Obtain listing of trainees or apprentices included in payroll for weeks selected for testing in 3 b.

i. Haphazardly select 5 trainees or apprentices from listing and compare the apprentice or trainee wage rates paid, per certified payroll, to the apprenticeship program-specific decrement factors

d. For the employees selected in a above agree the payroll amount, per certified payroll, to employee check stub/pay statement.

e. Perform employee inquiry of 40 individuals on job classification and agree job classification noted by employee to classification within payroll system.

5. Record retention requirements

a. Inspect physical or electronic records for evidence that weekly certified payroll records are retained for period specified in contract.

Vogtle Project

Site employee inquiry

1. Are you aware that the Vogtle 3 and 4 construction project is subject to the prevailing wage provisons of the Davis-Bacon Act of 1931?

Yes / No

2. Have you seen the Davis-Bacon Act poster(s) on this construction site?

Yes / No

3. Please provide your name and employee job classification

Name:______________________________________________

Job Classification:______________________________________

EX-10.E.1

EXHIBIT 10(e)1

BASE SALARIES OF NAMED EXECUTIVE OFFICERS

MISSISSIPPI POWER COMPANY

The following are the annual base salaries, effective March 1, 2014 unless otherwise noted, of the Chief Executive Officer and Chief Financial Officer of Mississippi Power Company and certain other executive officers of Mississippi Power Company who served during 2013.

G. Edison Holland, Jr. President and Chief Executive Officer	$665,176
Edward Day, VI* President and Chief Executive Officer	$418,454
Moses Feagin Vice President, Treasurer and Chief Financial Officer	$252,668
John W. Atherton Vice President	$258,975
Jeff G. Franklin Vice President	$256,531
John C. Huggins Vice President	$212,513

*Retired May 20, 2013. Salary shown was Mr. Day’s salary effective March 1, 2013.

EX-24.B.2

Exhibit 24(b)2

April 25, 2014

Art P. Beattie 30 Ivan Allen Jr. Blvd., NW Atlanta, GA 30308 Ms. Melissa K. Caen 30 Ivan Allen Jr. Blvd., NW Atlanta, GA 30308

Dear Mr. Beattie and Ms. Caen:

As a director and an officer of Alabama Power Company, I hereby make, constitute, and appoint you my true and lawful Attorney in my name, place and stead, to sign and cause to be filed with the Securities and Exchange Commission (1) this Company's Quarterly Reports on Form 10-Q during 2014, and (2) any necessary or appropriate amendment or amendments to any such reports and to this Company’s Annual Report on Form 10-K for the year ended December 31, 2013, each such report or amendments to such reports to be accompanied in each case by any necessary or appropriate exhibits or schedules thereto.

Yours very truly,

/s/Mark A. Crosswhite

Mark A. Crosswhite

EX-31.A.1

Exhibit 31(a)1

THE SOUTHERN COMPANY

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, Thomas A. Fanning, certify that:

1. I have reviewed this quarterly report on Form 10-Q of The Southern Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  May 8, 2014

/s/Thomas A. Fanning

Thomas A. Fanning

Chairman, President and

Chief Executive Officer

EX-31.A.2

Exhibit 31(a)2

THE SOUTHERN COMPANY

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, Art P. Beattie, certify that:

1. I have reviewed this quarterly report on Form 10-Q of The Southern Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  May 8, 2014

/s/Art P. Beattie

Art P. Beattie

Executive Vice President and Chief Financial Officer

EX-31.B.1

Exhibit 31(b)1

ALABAMA POWER COMPANY

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, Mark A. Crosswhite, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Alabama Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  May 8, 2014

/s/Mark A. Crosswhite

Mark A. Crosswhite

Chairman, President and Chief Executive Officer

EX-31.B.2

Exhibit 31(b)2

ALABAMA POWER COMPANY

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, Philip C. Raymond, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Alabama Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  May 8, 2014

/s/Philip C. Raymond

Philip C. Raymond

Executive Vice President, Chief Financial Officer

and Treasurer

EX-31.C.1

Exhibit 31(c)1

GEORGIA POWER COMPANY

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, W. Paul Bowers, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Georgia Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 8, 2014

/s/W. Paul Bowers 

W. Paul Bowers

President and Chief Executive Officer

EX-31.C.2

Exhibit 31(c)2

GEORGIA POWER COMPANY

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, W. Ron Hinson, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Georgia Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  May 8, 2014

/s/W. Ron Hinson

W. Ron Hinson

Executive Vice President, Chief Financial Officer and Treasurer

EX-31.D.1

Exhibit 31(d)1

GULF POWER COMPANY

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, S. W. Connally, Jr., certify that:

1. I have reviewed this quarterly report on Form 10-Q of Gulf Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  May 8, 2014

/s/S. W. Connally, Jr.

S. W. Connally, Jr.

President and Chief Executive Officer

EX-31.D.2

Exhibit 31(d)2

GULF POWER COMPANY

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, Richard S. Teel, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Gulf Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  May 8, 2014

/s/Richard S. Teel

Richard S. Teel

Vice President and Chief Financial Officer

EX-31.E.1

Exhibit 31(e)1

MISSISSIPPI POWER COMPANY

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, G. Edison Holland, Jr., certify that:

1. I have reviewed this quarterly report on Form 10-Q of Mississippi Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  May 8, 2014

/s/G. Edison Holland, Jr.

G. Edison Holland, Jr.

President, Chief Executive Officer and Chairman

EX-31.E.2

Exhibit 31(e)2

MISSISSIPPI POWER COMPANY

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, Moses H. Feagin, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Mississippi Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  May 8, 2014 

/s/Moses H. Feagin

Moses H. Feagin

Vice President, Treasurer and

Chief Financial Officer

EX-31.F.1

Exhibit 31(f)1

SOUTHERN POWER COMPANY

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, Oscar C. Harper IV, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Southern Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 8, 2014

/s/Oscar C. Harper IV

Oscar C. Harper IV

President and Chief Executive Officer

EX-31.F.2

Exhibit 31(f)2

SOUTHERN POWER COMPANY

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, William C. Grantham, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Southern Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  May 8, 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 March 31, 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 March 31, 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 March 31, 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

May 8, 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 March 31, 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 March 31, 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 March 31, 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

May 8, 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 March 31, 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 March 31, 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 March 31, 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

May 8, 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 March 31, 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 March 31, 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 March 31, 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

May 8, 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 March 31, 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 March 31, 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 March 31, 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

May 8, 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 March 31, 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 March 31, 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 March 31, 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

May 8, 2014

XML

Stockholders' Equity - Changes in Stockholders' Equity (Details) (USD $) Share data in Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014		Mar. 31, 2013
Changes in Stockholders' Equity
Beginning Balance	$ 19,764,000,000		$ 19,004,000,000
Net Income After Dividends on Preferred and Preference Stock	(351,000,000)	[1],[2]	(81,000,000)	[1]
Other comprehensive income (loss)	2,000,000		4,000,000
Stock Issued During Period, Value, Treasury Stock Reissued	111,000,000
Stock issued	53,000,000		99,000,000
Stock Repurchased During Period, Value	(4,000,000)		(18,000,000)
Cash dividends on common stock	(451,000,000)		(426,000,000)
Other	0		0
Ending Balance	19,826,000,000		18,744,000,000
Number of Common shares Issued [Member]
Changes in Stockholders' Equity
Beginning Balance, Shares	(892,733)		(877,803)
Stock issued, shares	1,340		2,638
Stock Repurchased During Period, Shares	0		0
Ending Balance, Shares	(894,073)		(880,441)
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	2,404
Stock Repurchased During Period, Shares	0		0
Other, Shares	(18)		(15)
Ending Balance, Shares	(3,261)		(10,050)
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	351,000,000		(81,000,000)
Other comprehensive income (loss)	2,000,000		4,000,000
Stock Issued During Period, Value, Treasury Stock Reissued	111,000,000
Stock issued	53,000,000		99,000,000
Stock Repurchased During Period, Value	(4,000,000)		(18,000,000)
Cash dividends on common stock	(451,000,000)		(426,000,000)
Other	0		0
Ending Balance	19,070,000,000		18,037,000,000
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	0		0
Stock Repurchased During Period, Value	0		0
Cash dividends on common stock	0
Other	0		0
Ending Balance	$ 756,000,000		$ 707,000,000

[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 March 31, 2014 includes a $380.0 million pre-tax charge ($234.7 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.

XML

Derivatives - Narrative (Details) (USD $)	3 Months Ended
	Mar. 31, 2014 MMBTU
Derivatives (Textual) [Abstract]
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints	7,000,000
Maximum potential collateral requirements arising the from credit-risk-related contingent features	$ 2,000,000
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
Maximum potential collateral requirements arising the from credit-risk-related contingent features	2,000,000
Georgia Power [Member]
Derivatives (Textual) [Abstract]
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints	4,000,000
Maximum potential collateral requirements arising the from credit-risk-related contingent features	2,000,000
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
Maximum potential collateral requirements arising the from credit-risk-related contingent features	2,000,000
Mississippi Power [Member]
Derivatives (Textual) [Abstract]
Maximum potential collateral requirements arising the from credit-risk-related contingent features	2,000,000
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
Maximum potential collateral requirements arising the from credit-risk-related contingent features	$ 2,000,000
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%

XML

Derivatives - Balance Sheet Offsetting (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014		Dec. 31, 2013
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 43		$ 27
Derivative Liability, Fair Value, Gross Liability	43		56
Alabama Power [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	12		7
Derivative Liability, Fair Value, Gross Liability	6		8
Georgia Power [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	8		5
Derivative Liability, Fair Value, Gross Liability	16		21
Gulf Power [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	12		7
Derivative Liability, Fair Value, Gross Liability	13		17
Mississippi Power [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	8		5
Derivative Liability, Fair Value, Gross Liability	8		10
Southern Power [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		1
Derivative Liability, Fair Value, Gross Liability			1
Energy Related Derivative [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Amount Offset Against Collateral	7		2
Derivative Liability, Fair Value, Amount Offset Against Collateral	(10)		34
Energy Related Derivative [Member] | Alabama Power [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Amount Offset Against Collateral	6		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	(5)		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	(3)		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]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	40	[1]	24	[2]
Derivative Liability, Fair Value, Gross Liability	(43)	[1]	56	[2]
Energy Related Derivative [Member] | Net Amount Of Derivatives [Member] | Alabama Power [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	12	[1]	7	[2]
Derivative Liability, Fair Value, Gross Liability	(6)	[1]	8	[2]
Energy Related Derivative [Member] | Net Amount Of Derivatives [Member] | Georgia Power [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	8	[1]	5	[2]
Derivative Liability, Fair Value, Gross Liability	(16)	[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	(13)	[1]	17	[2]
Energy Related Derivative [Member] | Net Amount Of Derivatives [Member] | Mississippi Power [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	8	[1]	5	[2]
Derivative Liability, Fair Value, Gross Liability	(8)	[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]
Derivative [Line Items]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	(33)	[3]	(22)	[4]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	33	[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	(6)	[3]	(5)	[4]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	6	[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	(8)	[3]	(5)	[4]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	8	[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	(5)	[3]	(4)	[4]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	5	[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.

XML

Contingencies and Regulatory Matters (Details) (USD $)	3 Months Ended					3 Months Ended		12 Months Ended					3 Months Ended	12 Months Ended	3 Months Ended		1 Months Ended		3 Months Ended		12 Months Ended						0 Months Ended	12 Months Ended	3 Months Ended		12 Months Ended	3 Months Ended		12 Months Ended			3 Months Ended		12 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Mar. 31, 2014 Alabama Power [Member]	Mar. 31, 2013 Alabama Power [Member]	Dec. 31, 2013 Alabama Power [Member]	Mar. 31, 2014 Georgia Power [Member]	Mar. 31, 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]	Mar. 31, 2014 Georgia Power [Member] Minimum [Member]	Dec. 31, 2013 Georgia Power [Member] Maximum [Member]	Mar. 31, 2014 Gulf Power [Member] clause	Mar. 31, 2013 Gulf Power [Member]	Mar. 31, 2013 Mississippi Power [Member]	Mar. 31, 2012 Mississippi Power [Member]	Mar. 31, 2014 Mississippi Power [Member]	Mar. 31, 2013 Mississippi Power [Member]	Dec. 31, 2013 Mississippi Power [Member]	Jan. 02, 2014 Mississippi Power [Member]	Dec. 31, 2012 Mississippi Power [Member]	Dec. 31, 2010 Mississippi Power [Member]	Jan. 31, 2013 Mississippi Power [Member] Maximum [Member]	Mar. 31, 2014 Gulf Power and Mississippi Power [Member]	Feb. 26, 2013 Electricity Generation Plant, Non-Nuclear [Member] Mississippi Power [Member]	Dec. 31, 2012 Electricity Generation Plant, Non-Nuclear [Member] Mississippi Power [Member]	Mar. 31, 2014 Kemper IGCC [Member]	Mar. 31, 2013 Kemper IGCC [Member]	Dec. 31, 2013 Kemper IGCC [Member]	Mar. 31, 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]	Mar. 31, 2013 Kemper IGCC [Member] Mississippi Power [Member] MW	Mar. 31, 2014 Kemper IGCC [Member] Mississippi Power [Member] Minimum [Member]	Mar. 31, 2014 Kemper IGCC [Member] Mississippi Power [Member] Maximum [Member]	Dec. 31, 2010 Mine [Member] Mississippi Power [Member]	Mar. 31, 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]	Mar. 31, 2014 Storm Reserve [Member] Georgia Power [Member]	Dec. 31, 2013 Storm Reserve [Member] Georgia Power [Member]	May 06, 2014 Subsequent Event [Member] Mississippi Power [Member]	Apr. 01, 2014 Subsequent Event [Member] Mississippi Power [Member]
Loss Contingencies [Line Items]
Loss Contingency, Estimate of Possible Loss																			$ 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						18,000,000									50,000,000
Civil penalties per day violation rate						37,500
Number of times of punitive damages in comparison to cost incurred by Environmental Protection Agency						3
Damages awarded			17,000,000			27,000,000
Amount have been recognized in the financial statements for the second claim						0
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
Retail Regulatory Matters
Under recovered rate CNP balance			23,000,000		18,000,000
Under recovered rate CNP environmental balance			13,000,000		7,000,000
Over Recovered Fuel Cost																					14,500,000
Under recovered regulatory clause revenues																			1,800,000
Accumulated reserve balance for future storms			91,000,000		96,000,000
Over recovered fuel cost balance																																								157,000,000	58,000,000
Regulatory Assets																																										110,000,000	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
Amortization to earnings of financing costs capitalized, amortization term						5 years
Costs included in CWIP						32,000,000													2,670,000,000
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															6,200,000
Psc Approved Annual Property Damage Reserve Accrual																																													3,300,000
Ownership percentage in scrubber project															50.00%				50.00%
Estimated cost of scrubber project																			330,000,000							660,000,000
Scrubber project expenditures amount																			188,100,000							370,200,000
Allowance For Funds Used During Construction Cost																			10,700,000
Integrated Coal Gasification Combined Cycle [Abstract]
Estimated Cost																												2,400,000,000				3,520,000,000	[1]		2,880,000,000
Period Rate Plan For Cost Accrued Through Additional Prudence Review																			7 years
Revisions To Revenue Requirement																			45,000,000
Alternate Financing																											1,000,000,000
Revenue Requirement Obligations																																					120,000,000	150,000,000
Costs associated with CCP12 grant funds																							245,300,000
Maximum Cap Construction Cost																																4,320,000,000	[1],[2]
Pre-tax charge to income																													380,000,000	540,000,000	1,180,000,000	380,000,000		1,180,000,000
After tax charge to income																													234,700,000	333,500,000	728,700,000	234,700,000		728,700,000
Costs Due To Extension Of In-service Date																			25,000,000
Costs included in CWIP						32,000,000													2,670,000,000
Cost deferred in other regulatory assets																			83,900,000
Other deferred charges and assets																			3,900,000
Previously expensed																			1,100,000
Settlement Agreement To Increase Rates																									172,000,000
Prudence Review Of Plant Cost Within Settlement Agreement																			6 months
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
Regulatory Liabilities																			135,500,000
Retail Revenues	3,858,000,000	3,298,000,000	1,297,000,000	1,141,000,000		2,050,000,000	1,729,000,000								303,120,000	259,877,000			207,038,000	168,310,000												4,400,000
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%
Percentage of Contract to Purchase Carbon Dioxide from Project																			30.00%
Purchase of Interest																					17.50%			17.50%
Deposit received																						75,000,000	150,000,000
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
Additional Bonus Depreciation For Property Acquired Future Periods																			50.00%
Positive Impact From Bonus Depreciation																																170,000,000
Electric Generating Units, Capacity																																				75
Capacity Revenues Under Power Supply Agreement																					$ 17,500,000
Number Of Regulatory Clauses															4

[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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Stockholders' Equity (Tables)

3 Months Ended

Mar. 31, 2014

Equity [Abstract]

Earnings per Share

Shares used to compute diluted earnings per share were as follows:

	Three Months Ended March 31, 2014	Three Months Ended March 31, 2013
	(in millions)
As reported shares	890	870
Effect of options and performance share award units	3	5
Diluted shares	893	875

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	—	—		351			—		351
Other comprehensive income (loss)	—	—		2			—		2
Treasury stock re-issued	—	2,404		111			—		111
Stock issued	1,340	—		53			—		53
Stock repurchased, at cost	—	—		(4		)	—		(4		)
Cash dividends on common stock	—	—		(451		)	—		(451		)
Other	—	(18	)	—			—		—
Balance at March 31, 2014	894,073	(3,261	)	$	19,070		$	756	$	19,826
Balance at December 31, 2012	877,803	(10,035	)	$	18,297		$	707	$	19,004
Net income after dividends on preferred and preference stock	—	—		81			—		81
Other comprehensive income (loss)	—	—		4			—		4
Stock issued	2,638	—		99			—		99
Stock repurchased, at cost	—	—		(18		)	—		(18		)
Cash dividends on common stock	—	—		(426		)	—		(426		)
Other	—	(15	)	—			—		—
Balance at March 31, 2013	880,441	(10,050	)	$	18,037		$	707	$	18,744

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Segment and Related Information - Financial Data for Business Segments (Details) (USD $)	3 Months Ended				12 Months Ended
	Mar. 31, 2014		Mar. 31, 2013		Dec. 31, 2013
Segment Reporting Information [Line Items]
Number of States in which Entity Operates	4
Segment and Related Information (Textual) [Abstract]
Electric Utilities' Revenues	$ 4,644,000,000		$ 3,897,000,000
Financial data for business segments
Electric Utilities' Revenues	4,644,000,000		3,897,000,000
Segment net income (loss)	351,000,000	[1],[2]	81,000,000	[1]
Total assets	64,838,000,000				64,546,000,000
Electric Utilities [Member]
Segment and Related Information (Textual) [Abstract]
Electric Utilities' Revenues	4,627,000,000		3,885,000,000
Financial data for business segments
Electric Utilities' Revenues	4,627,000,000		3,885,000,000
Segment net income (loss)	351,000,000	[1],[2]	95,000,000	[1]
Total assets	64,160,000,000				63,775,000,000
Traditional Operating Companies [Member] | Electric Utilities [Member]
Segment and Related Information (Textual) [Abstract]
Electric Utilities' Revenues	4,378,000,000		3,668,000,000
Financial data for business segments
Electric Utilities' Revenues	4,378,000,000		3,668,000,000
Segment net income (loss)	318,000,000	[1],[2]	66,000,000	[1]
Total assets	59,854,000,000				59,447,000,000
Southern Power [Member]
Segment and Related Information (Textual) [Abstract]
Electric Utilities' Revenues	72,000,000		78,000,000
Financial data for business segments
Electric Utilities' Revenues	72,000,000		78,000,000
Southern Power [Member] | Electric Utilities [Member]
Segment and Related Information (Textual) [Abstract]
Electric Utilities' Revenues	351,000,000		303,000,000
Financial data for business segments
Electric Utilities' Revenues	351,000,000		303,000,000
Segment net income (loss)	33,000,000	[1],[2]	29,000,000	[1]
Total assets	4,404,000,000				4,429,000,000
Eliminations [Member]
Segment and Related Information (Textual) [Abstract]
Electric Utilities' Revenues	(24,000,000)		(23,000,000)
Financial data for business segments
Electric Utilities' Revenues	(24,000,000)		(23,000,000)
Segment net income (loss)	0	[1],[2]	2,000,000	[1]
Total assets	(415,000,000)				(306,000,000)
Eliminations [Member] | Electric Utilities [Member]
Segment and Related Information (Textual) [Abstract]
Electric Utilities' Revenues	(102,000,000)		(86,000,000)
Financial data for business segments
Electric Utilities' Revenues	(102,000,000)		(86,000,000)
Segment net income (loss)	0	[1],[2]	0	[1]
Total assets	(98,000,000)				(101,000,000)
All Other [Member]
Segment and Related Information (Textual) [Abstract]
Electric Utilities' Revenues	41,000,000		35,000,000
Financial data for business segments
Electric Utilities' Revenues	41,000,000		35,000,000
Segment net income (loss)	0	[1],[2]	(16,000,000)	[1]
Total assets	1,093,000,000				1,077,000,000
Kemper Igcc [Member]
Financial data for business segments
Pre-tax charge to income	380,000,000		540,000,000		1,180,000,000
After tax charge to income	$ 234,700,000		$ 333,500,000		$ 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 March 31, 2014 includes a $380.0 million pre-tax charge ($234.7 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.

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Retirement Benefits (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Pension Plans [Member]
Pension Plans and Postretirement Plans
Service cost	$ 53	$ 58
Interest cost	109	97
Expected return on plan assets	(161)	(151)
Amortization:
Prior service costs	6	7
Net (gain)/loss	28	50
Net cost	35	61
Pension Plans [Member] | Alabama Power [Member]
Pension Plans and Postretirement Plans
Service cost	12	13
Interest cost	26	23
Expected return on plan assets	(42)	(39)
Amortization:
Prior service costs	1	2
Net (gain)/loss	8	13
Net cost	5	12
Pension Plans [Member] | Georgia Power [Member]
Pension Plans and Postretirement Plans
Service cost	16	17
Interest cost	38	34
Expected return on plan assets	(57)	(53)
Amortization:
Prior service costs	3	3
Net (gain)/loss	10	19
Net cost	10	20
Pension Plans [Member] | Gulf Power [Member]
Pension Plans and Postretirement Plans
Service cost	3	3
Interest cost	5	4
Expected return on plan assets	(7)	(6)
Amortization:
Prior service costs	0	0
Net (gain)/loss	1	2
Net cost	2	3
Pension Plans [Member] | Mississippi Power [Member]
Pension Plans and Postretirement Plans
Service cost	3	3
Interest cost	5	5
Expected return on plan assets	(7)	(7)
Amortization:
Prior service costs	0	0
Net (gain)/loss	1	2
Net cost	2	3
Other Postretirement Benefits [Member]
Pension Plans and Postretirement Plans
Service cost	5	6
Interest cost	20	19
Expected return on plan assets	(15)	(14)
Amortization:
Transition obligation		1
Prior service costs	1	1
Net (gain)/loss	1	3
Net cost	12	16
Other Postretirement Benefits [Member] | Alabama Power [Member]
Pension Plans and Postretirement Plans
Service cost	1	2
Interest cost	5	5
Expected return on plan assets	(6)	(6)
Amortization:
Transition obligation		0
Prior service costs	1	1
Net (gain)/loss	0	0
Net cost	1	2
Other Postretirement Benefits [Member] | Georgia Power [Member]
Pension Plans and Postretirement Plans
Service cost	2	2
Interest cost	8	8
Expected return on plan assets	(6)	(6)
Amortization:
Transition obligation		1
Prior service costs	0	0
Net (gain)/loss	0	2
Net cost	4	7
Other Postretirement Benefits [Member] | Gulf Power [Member]
Pension Plans and Postretirement Plans
Service cost	0	0
Interest cost	1	1
Expected return on plan assets	0	0
Amortization:
Transition obligation		0
Prior service costs	0	0
Net (gain)/loss	0	0
Net cost	1	1
Other Postretirement Benefits [Member] | Mississippi Power [Member]
Pension Plans and Postretirement Plans
Service cost	0	0
Interest cost	1	1
Expected return on plan assets	0	0
Amortization:
Transition obligation		0
Prior service costs	0	0
Net (gain)/loss	0	0
Net cost	$ 1	$ 1

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Fair Value Measurements - Narrative (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014
Fair Value Measurements (Textual) [Abstract]
Increase (decrease) in fair value of funds including reinvested interest and dividends	$ 27
Alabama Power [Member]
Fair Value Measurements (Textual) [Abstract]
Increase (decrease) in fair value of funds including reinvested interest and dividends	16
Georgia Power [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Notices Of Withdrawal Foreign Equity Funds	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	90 days
Commingled Funds	7
Fair Value Measurements (Textual) [Abstract]
Increase (decrease) in fair value of funds including reinvested interest and dividends	11
Minimum [Member] | Georgia Power [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Withdrawal Of Foreign Equity Fund Investment	1
Foreign Equity Fund Investment	$ 10

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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	Mar. 31, 2014	Dec. 31, 2013
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	$ (3)	$ (32)
Alabama Power [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	6	(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)	0	(5)
Other regulatory assets current [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	(17)	(26)
Other regulatory assets current [Member] | Alabama Power [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	(1)	(3)
Other regulatory assets current [Member] | Georgia Power [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	(10)	(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]
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	(26)	(29)
Other regulatory assets deferred [Member] | Alabama Power [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	(5)	(5)
Other regulatory assets deferred [Member] | Georgia Power [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	(6)	(8)
Other regulatory assets deferred [Member] | Gulf Power [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	(9)	(11)
Other regulatory assets deferred [Member] | Mississippi Power [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	(6)	(6)
Other regulatory liabilities current [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	36	16
Other regulatory liabilities current [Member] | Alabama Power [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	11	5
Other regulatory liabilities current [Member] | Georgia Power [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	8	3
Other regulatory liabilities current [Member] | Gulf Power [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	10	5
Other regulatory liabilities current [Member] | Mississippi Power [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	7	3
Other regulatory liabilities deferred [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	4	7
Other regulatory liabilities deferred [Member] | Alabama Power [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	1	2
Other regulatory liabilities deferred [Member] | Georgia Power [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	0	2
Other regulatory liabilities deferred [Member] | Gulf Power [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	2	2
Other regulatory liabilities deferred [Member] | Mississippi Power [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total energy-related derivative gains (losses)	$ 1	$ 2

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Introduction

3 Months Ended

Mar. 31, 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 March 31, 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 filings 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 quarter 2014 and is not expected to have a material impact on the financial statements of Southern Company or Southern Power in future periods.

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Effective Tax Rate - Narrative (Details)	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Effective Tax Rate and Unrecognized Tax Benefits (Textual) [Abstract]
Effective tax rate	32.30%	24.50%
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	38.00%	38.10%
Gulf Power [Member]
Effective Tax Rate and Unrecognized Tax Benefits (Textual) [Abstract]
Effective tax rate	37.40%	37.60%
Mississippi Power [Member]
Effective Tax Rate and Unrecognized Tax Benefits (Textual) [Abstract]
Effective tax rate	(43.00%)	(40.80%)
Southern Power [Member]
Effective Tax Rate and Unrecognized Tax Benefits (Textual) [Abstract]
Effective tax rate	8.50%	33.50%

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Segment and Related Information (Tables)

3 Months Ended

Mar. 31, 2014

Segment Reporting [Abstract]

Financial data for business segments

Financial data for business segments and products and services for the three months ended March 31, 2014 and 2013 was as follows:

	Electric Utilities
	Traditional Operating Companies		Southern Power		Eliminations			Total		All Other			Eliminations			Consolidated
	(in millions)
Three Months Ended March 31, 2014:
Operating revenues	$	4,378	$	351	$	(102	)	$	4,627	$	41		$	(24	)	$	4,644
Segment net income (loss)(a)(b)	318		33		—			351		—			—			351
Total assets at March 31, 2014	$	59,854	$	4,404	$	(98	)	$	64,160	$	1,093		$	(415	)	$	64,838
Three Months Ended March 31, 2013:
Operating revenues	$	3,668	$	303	$	(86	)	$	3,885	$	35		$	(23	)	$	3,897
Segment net income (loss)(a)(c)	66		29		—			95		(16		)	2			81
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 March 31, 2014 includes a $380.0 million pre-tax charge ($234.7 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 three months ended March 31, 2013 includes $540.0 million in pre-tax charges ($333.5 million after tax) for estimated probable losses on the Kemper IGCC. See Note (B) under "Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" herein for additional information.

Financial data for products and services

Products and Services

	Electric Utilities' Revenues
Period	Retail		Wholesale		Other		Total
	(in millions)
Three Months Ended March 31, 2014	$	3,858	$	604	$	165	$	4,627
Three Months Ended March 31, 2013	3,298		432		155		3,885

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Derivatives (Tables)

3 Months Ended

Mar. 31, 2014

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of derivatives

At March 31, 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	256	2018	2017
Alabama Power	65	2017	—
Georgia Power	53	2017	—
Gulf Power	83	2018	—
Mississippi Power	54	2017	—
Southern Power	1	—	2017

Notional amount of interest rate derivatives

At March 31, 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) March 31, 2014
	(in millions)					(in millions)
Fair value hedges of existing debt
Southern Company	$	350	4.15%	3-month LIBOR  + 1.96%	May 2014	$	3

Fair value of energy-related derivatives and interest rate derivatives

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

Asset Derivatives at March 31, 2014
	Fair Value
Derivative Category and Balance Sheet Location	Southern Company		Alabama Power		Georgia Power		Gulf Power		Mississippi Power		Southern Power
	(in millions)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets	$	36	$	11	$	8	$	10	$	7
Other deferred charges and assets	4		1		—		2		1
Total derivatives designated as hedging instruments for regulatory purposes	$	40	$	12	$	8	$	12	$	8	N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current assets	3		—		—		—		—		$	—
Total asset derivatives	$	43	$	12	$	8	$	12	$	8	$	—

Liability Derivatives at March 31, 2014
	Fair Value
Derivative Category and Balance Sheet Location	Southern Company		Alabama Power		Georgia Power		Gulf Power		Mississippi Power		Southern Power
	(in millions)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Liabilities from risk management activities	$	17	$	1	$	10	$	4	$	2
Other deferred credits and liabilities	26		5		6		9		6
Total liability derivatives	$	43	$	6	$	16	$	13	$	8	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 Assets And Liabilities [Table Text Block]

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 March 31, 2014
	Fair Value
	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power			Southern Power
	(in millions)
Assets
Energy-related derivatives:
Energy-related derivatives presented in the Balance Sheet (a)	$	40		$	12		$	8		$	12		$	8		$	—
Gross amounts not offset in the Balance Sheet (b)	(33		)	(6		)	(8		)	(8		)	(5		)	—
Net energy-related derivative assets	$	7		$	6		$	—		$	4		$	3		$	—
Liabilities
Energy-related derivatives:
Energy-related derivatives presented in the Balance Sheet (a)	$	(43	)	$	(6	)	$	(16	)	$	(13	)	$	(8	)	$	—
Gross amounts not offset in the Balance Sheet (b)	33			6			8			8			5			—
Net energy-related derivative liabilities	$	(10	)	$	—		$	(8	)	$	(5	)	$	(3	)	$	—

(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 March 31, 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 March 31, 2014
Derivative Category and Balance Sheet Location	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power
	(in millions)
Energy-related derivatives:
Other regulatory assets, current	$	(17	)	$	(1	)	$	(10	)	$	(4	)	$	(2	)
Other regulatory assets, deferred	(26		)	(5		)	(6		)	(9		)	(6		)
Other regulatory liabilities, current	36			11			8			10			7
Other regulatory liabilities, deferred	4			1			—			2			1
Total energy-related derivative gains (losses)	$	(3	)	$	6		$	(8	)	$	(1	)	$	—

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 - Schedule of Derivatives and Gains (Losses) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014
Notional amount of interest rate derivatives
Notional Amount	$ 350
Interest Rate Paid, basis spread on LIBOR	1.96%
Fair Value Hedging [Member]
Notional amount of interest rate derivatives
Interest Rate Received	4.15%
Weighted Average Interest Rate Paid	3-month LIBOR  + 1.96%
Hedge Maturity Date	May 31, 2014
Fair Value Gain (Loss) March 31, 2014	$ 3
Gas [Member]
Energy-related derivative contracts
Net Purchased mmBtu	256,000,000
Longest Hedge Date1	2018
Longest Non-hedge Date1	2017
Gas [Member] | Alabama Power [Member]
Energy-related derivative contracts
Net Purchased mmBtu	65,000,000
Longest Hedge Date1	2017
Gas [Member] | Georgia Power [Member]
Energy-related derivative contracts
Net Purchased mmBtu	53,000,000
Longest Hedge Date1	2017
Gas [Member] | Gulf Power [Member]
Energy-related derivative contracts
Net Purchased mmBtu	83,000,000
Longest Hedge Date1	2018
Gas [Member] | Mississippi Power [Member]
Energy-related derivative contracts
Net Purchased mmBtu	54,000,000
Longest Hedge Date1	2017
Gas [Member] | Southern Power [Member]
Energy-related derivative contracts
Net Purchased mmBtu	1,000,000
Longest Non-hedge Date1	2017

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Contingencies and Regulatory Matters Retail Regulatory Matters (Details) (USD $)	Mar. 31, 2014	Dec. 31, 2013
Loss Contingencies [Line Items]
Other Regulatory Liabilities, Current	$ 116,000,000	$ 92,000,000
Alabama Power [Member]
Loss Contingencies [Line Items]
Under recovered rate CNP environmental balance	13,000,000	7,000,000
Under Recovered Rate Cnp Balance	23,000,000	18,000,000
Other Regulatory Liabilities, Current	36,000,000	37,000,000
Deferred Over Recovered Regulatory Clause Revenues	0	15,000,000
Accumulated reserve balance for future storms	91,000,000	96,000,000
Fuel Recovery Clause [Member] | Alabama Power [Member]
Loss Contingencies [Line Items]
Other Regulatory Liabilities, Current	22,000,000	27,000,000
Deferred Over Recovered Regulatory Clause Revenues	$ 0	$ 15,000,000

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Contingencies and Regulatory Matters Cost Recovery Clause (Details) (Gulf Power [Member], USD $) In Millions, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Under Recovered Regulatory Clause Revenues [Member]
Loss Contingencies [Line Items]
Under Recovered Fuel Cost	$ 35.7	$ 21.0
Under Recovered Purchased Power Capacity Costs	0	2.8
Under Recovered Environmental Cost	17.1	14.4
Under Recovered Energy Conservation Costs	6.3	7.0
Other regulatory liabilities current [Member]
Loss Contingencies [Line Items]
Over Recovered Purchased Power Capacity Costs	$ 5.5	$ 0

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Condensed Consolidated Balance Sheets (Unaudited) - Parenthetical (USD $) In Thousands, except Share data, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Common stock, par value per share	$ 5	$ 5
Common stock, shares authorized	1,500,000,000	1,500,000,000
Common stock, shares issued	894,000,000	893,000,000
Treasury shares at cost	3,300,000	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	$ 6,232	$ 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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Contingencies and Regulatory Matters Current And Actual Cost Estimate (Details) (Kemper Igcc [Member], Mississippi Power [Member], USD $) In Billions, unless otherwise specified	3 Months Ended		12 Months Ended
	Mar. 31, 2014		Dec. 31, 2012
Loss Contingencies [Line Items]
Estimated Cost	$ 3.52	[1]	$ 2.88
Cost Of Lignite Mine And Equipment	0.23
Cost Of CO2 Pipeline Facilities	0.10
Cost Of AFUDC	0.32	[2],[3]
Plant General Exceptions	0.07
Plant Regulatory Asset	0.08	[2],[4]
Maximum Cap Construction Cost	4.32	[1],[2]
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	[2],[4]
Maximum Cap Construction Cost	2.97	[1],[2]
Current Estimate [Member]
Loss Contingencies [Line Items]
Estimated Cost	4.44	[1]
Cost Of Lignite Mine And Equipment	0.23
Cost Of CO2 Pipeline Facilities	0.11
Cost Of AFUDC	0.55	[2],[3]
Plant General Exceptions	0.10
Plant Regulatory Asset	0.10	[2],[4]
Maximum Cap Construction Cost	$ 5.53	[1],[2]

[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.

[3] 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."

[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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Financing (Details) (USD $) In Millions, unless otherwise specified	1 Months Ended	3 Months Ended
	Jan. 31, 2014	Mar. 31, 2014
Credit arrangements by company
Expires, 2014		$ 523
Expires, 2015		95
Expires, 2016		480
Expires, 2018		4,130	[1]
Total		5,228
Unused		5,214
Executable Term-Loans, One Year		153
Executable Term-Loans, Two Years		40
Due Within One Year, Term Out		193
Due Within One Year, No Term Out		365
Southern Company [Member]
Credit arrangements by company
Expires, 2014		0	[1]
Expires, 2015		0	[1]
Expires, 2016		0	[1]
Expires, 2018		1,000	[1]
Total		1,000
Unused		1,000
Executable Term-Loans, One Year		0
Executable Term-Loans, Two Years		0
Due Within One Year, Term Out		0
Due Within One Year, No Term Out		0
Alabama Power [Member]
Credit arrangements by company
Expires, 2014		238	[1]
Expires, 2015		35	[1]
Expires, 2016		0	[1]
Expires, 2018		1,030	[1]
Total		1,303
Unused		1,303
Executable Term-Loans, One Year		53
Executable Term-Loans, Two Years		0
Due Within One Year, Term Out		53
Due Within One Year, No Term Out		185
Georgia Power [Member]
Credit arrangements by company
Expires, 2014		0	[1]
Expires, 2015		0	[1]
Expires, 2016		150	[1]
Expires, 2018		1,600	[1]
Total		1,750
Unused		1,736
Executable Term-Loans, One Year		0
Executable Term-Loans, Two Years		0
Due Within One Year, Term Out		0
Due Within One Year, No Term Out		0
Gulf Power [Member]
Credit arrangements by company
Expires, 2014		75	[1]
Expires, 2015		35	[1]
Expires, 2016		165	[1]
Expires, 2018		0	[1]
Total		275
Unused		275
Executable Term-Loans, One Year		50
Executable Term-Loans, Two Years		0
Due Within One Year, Term Out		50
Due Within One Year, No Term Out		60
Mississippi Power [Member]
Line of Credit Facility [Line Items]
Bank Loans Period Of Extension	18 months
Credit arrangements by company
Expires, 2014		135	[1]
Expires, 2015		0	[1]
Expires, 2016		165	[1]
Expires, 2018		0	[1]
Total		300
Unused		300
Executable Term-Loans, One Year		25
Executable Term-Loans, Two Years		40
Due Within One Year, Term Out		65
Due Within One Year, No Term Out		70
Debt Instrument, Description of Variable Rate Basis		P1M
Aggregate Principal Amount Of Floating Rate Bank Loan	250
Southern Power [Member]
Credit arrangements by company
Expires, 2014		0	[1]
Expires, 2015		0	[1]
Expires, 2016		0	[1]
Expires, 2018		500	[1]
Total		500
Unused		500
Executable Term-Loans, One Year		0
Executable Term-Loans, Two Years		0
Due Within One Year, Term Out		0
Due Within One Year, No Term Out		0
Other Subsidiaries [Member]
Credit arrangements by company
Expires, 2014		75	[1]
Expires, 2015		25	[1]
Expires, 2016		0	[1]
Expires, 2018		0	[1]
Total		100
Unused		100
Executable Term-Loans, One Year		25
Executable Term-Loans, Two Years		0
Due Within One Year, Term Out		25
Due Within One Year, No Term Out		$ 50

[1] No credit arrangements expire in 2017.

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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
	Mar. 31, 2014		Mar. 31, 2013
Operating Revenues:
Retail revenues	$ 3,858,000,000		$ 3,298,000,000
Wholesale revenues	604,000,000		432,000,000
Other electric revenues	165,000,000		155,000,000
Other revenues	17,000,000		12,000,000
Total operating revenues	4,644,000,000		3,897,000,000
Operating Expenses:
Fuel	1,647,000,000		1,262,000,000
Purchased power	187,000,000		95,000,000
Other operations and maintenance	986,000,000		974,000,000
Depreciation and amortization	497,000,000		466,000,000
Taxes other than income taxes	247,000,000		235,000,000
Estimated loss on Kemper IGCC	380,000,000		540,000,000
Total operating expenses	3,944,000,000		3,572,000,000
Operating Income	700,000,000		325,000,000
Other Income and (Expense):
Allowance for equity funds used during construction	57,000,000		41,000,000
Interest expense, net of amounts capitalized	(206,000,000)		(211,000,000)
Other income (expense), net	(7,000,000)		(27,000,000)
Total other income and (expense)	(156,000,000)		(197,000,000)
Earnings Before Income Taxes	544,000,000		128,000,000
Income taxes	176,000,000		31,000,000
Consolidated Net Income	368,000,000		97,000,000
Less: Net income attributable to noncontrolling interest	17,000,000		16,000,000
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries	351,000,000	[1],[2]	81,000,000	[1]
Earnings per share (EPS) -
Basic EPS (in dollars per share)	$ 0.39		$ 0.09
Diluted EPS (in dollars per share)	$ 0.39		$ 0.09
Average number of shares of common stock outstanding (in millions)
Basic (in shares)	890		870
Diluted (in shares)	893		875
Cash dividends paid per share of common stock	$ 0.5075		$ 0.4900
Alabama Power [Member]
Operating Revenues:
Retail revenues	1,297,000,000		1,141,000,000
Wholesale revenues, non-affiliates	85,000,000		59,000,000
Wholesale revenues, affiliates	69,000,000		56,000,000
Other revenues	57,000,000		52,000,000
Total operating revenues	1,508,000,000		1,308,000,000
Operating Expenses:
Fuel	432,000,000		372,000,000
Purchased power, non-affiliates	57,000,000		20,000,000
Purchased power, affiliates	49,000,000		31,000,000
Other operations and maintenance	325,000,000		330,000,000
Depreciation and amortization	175,000,000		158,000,000
Taxes other than income taxes	89,000,000		90,000,000
Total operating expenses	1,127,000,000		1,001,000,000
Operating Income	381,000,000		307,000,000
Other Income and (Expense):
Allowance for equity funds used during construction	10,000,000		8,000,000
Interest expense, net of amounts capitalized	(62,000,000)		(66,000,000)
Other income (expense), net	(5,000,000)		(1,000,000)
Total other income and (expense)	(57,000,000)		(59,000,000)
Earnings Before Income Taxes	324,000,000		248,000,000
Income taxes	127,000,000		97,000,000
Consolidated Net Income	197,000,000		151,000,000
Dividends on Preferred and Preference Stock	10,000,000		10,000,000
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries	187,000,000		141,000,000
Georgia Power [Member]
Operating Revenues:
Retail revenues	2,050,000,000		1,729,000,000
Wholesale revenues, non-affiliates	109,000,000		62,000,000
Wholesale revenues, affiliates	21,000,000		6,000,000
Other revenues	89,000,000		85,000,000
Total operating revenues	2,269,000,000		1,882,000,000
Operating Expenses:
Fuel	752,000,000		519,000,000
Purchased power, non-affiliates	79,000,000		50,000,000
Purchased power, affiliates	184,000,000		175,000,000
Other operations and maintenance	427,000,000		431,000,000
Depreciation and amortization	208,000,000		200,000,000
Taxes other than income taxes	103,000,000		95,000,000
Total operating expenses	1,753,000,000		1,470,000,000
Operating Income	516,000,000		412,000,000
Other Income and (Expense):
Allowance for equity funds used during construction	6,000,000		6,000,000
Interest expense, net of amounts capitalized	(84,000,000)		(91,000,000)
Other income (expense), net	(2,000,000)		(2,000,000)
Total other income and (expense)	(80,000,000)		(87,000,000)
Earnings Before Income Taxes	436,000,000		325,000,000
Income taxes	166,000,000		124,000,000
Consolidated Net Income	270,000,000		201,000,000
Dividends on Preferred and Preference Stock	4,000,000		4,000,000
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries	266,000,000		197,000,000
Gulf Power [Member]
Operating Revenues:
Retail revenues	303,120,000		259,877,000
Wholesale revenues, non-affiliates	35,592,000		21,208,000
Wholesale revenues, affiliates	52,778,000		29,455,000
Other revenues	15,642,000		15,734,000
Total operating revenues	407,132,000		326,274,000
Operating Expenses:
Fuel	168,422,000		120,846,000
Purchased power, non-affiliates	15,461,000		11,135,000
Purchased power, affiliates	6,504,000		3,312,000
Other operations and maintenance	84,201,000		78,662,000
Depreciation and amortization	31,857,000		37,053,000
Taxes other than income taxes	26,799,000		23,626,000
Total operating expenses	333,244,000		274,634,000
Operating Income	73,888,000		51,640,000
Other Income and (Expense):
Allowance for equity funds used during construction	2,379,000		1,134,000
Interest expense, net of amounts capitalized	(13,264,000)		(14,369,000)
Other income (expense), net	(725,000)		(976,000)
Total other income and (expense)	(11,610,000)		(14,211,000)
Earnings Before Income Taxes	62,278,000		37,429,000
Income taxes	23,284,000		14,086,000
Consolidated Net Income	38,994,000		23,343,000
Dividends on Preferred and Preference Stock	2,251,000		1,551,000
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries	36,743,000		21,792,000
Mississippi Power [Member]
Operating Revenues:
Retail revenues	207,038,000		168,310,000
Wholesale revenues, non-affiliates	96,718,000		65,109,000
Wholesale revenues, affiliates	22,789,000		8,341,000
Other revenues	4,616,000		4,174,000
Total operating revenues	331,161,000		245,934,000
Operating Expenses:
Fuel	146,951,000		104,564,000
Purchased power, non-affiliates	11,494,000		1,367,000
Purchased power, affiliates	8,929,000		9,689,000
Other operations and maintenance	66,095,000		54,812,000
Depreciation and amortization	22,694,000		23,233,000
Taxes other than income taxes	20,458,000		19,417,000
Estimated loss on Kemper IGCC	380,000,000		462,000,000
Total operating expenses	656,621,000		675,082,000
Operating Income	(325,460,000)		(429,148,000)
Other Income and (Expense):
Allowance for equity funds used during construction	38,082,000		26,074,000
Interest expense, net of amounts capitalized	(12,035,000)		(10,409,000)
Other income (expense), net	(1,799,000)		(1,547,000)
Total other income and (expense)	24,248,000		14,118,000
Earnings Before Income Taxes	(301,212,000)		(415,030,000)
Income taxes	(129,597,000)		(169,142,000)
Consolidated Net Income	(171,615,000)		(245,888,000)
Dividends on Preferred and Preference Stock	433,000		433,000
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries	(172,048,000)		(246,321,000)
Southern Power [Member]
Operating Revenues:
Wholesale revenues, non-affiliates	277,868,000		223,429,000
Wholesale revenues, affiliates	72,333,000		78,191,000
Other revenues	653,000		1,327,000
Total operating revenues	350,854,000		302,947,000
Operating Expenses:
Fuel	124,562,000		119,372,000
Purchased power, non-affiliates	27,893,000		14,573,000
Purchased power, affiliates	29,186,000		7,865,000
Other operations and maintenance	52,715,000		50,950,000
Depreciation and amortization	51,457,000		40,160,000
Taxes other than income taxes	5,683,000		5,354,000
Total operating expenses	291,496,000		238,274,000
Operating Income	59,358,000		64,673,000
Other Income and (Expense):
Interest expense, net of amounts capitalized	(22,003,000)		(20,394,000)
Other income (expense), net	118,000		(257,000)
Total other income and (expense)	(21,885,000)		(20,651,000)
Earnings Before Income Taxes	37,473,000		44,022,000
Income taxes	3,186,000		14,830,000
Consolidated Net Income	34,287,000		29,192,000
Less: Net income attributable to noncontrolling interest	816,000		0
Average number of shares of common stock outstanding (in millions)
Net income attributable to Southern Power Company	$ 33,471,000		$ 29,192,000

[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 March 31, 2014 includes a $380.0 million pre-tax charge ($234.7 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.

XML

Derivatives - Balance Sheet Presentation (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 43	$ 27
Derivative Liability, Fair Value, Gross Liability	43	56
Hedging Instruments for Regulatory Purposes [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	40	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	17	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	26	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	36	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	4	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	3
Alabama Power [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	12	7
Derivative Liability, Fair Value, Gross Liability	6	8
Alabama Power [Member] | Hedging Instruments for Regulatory Purposes [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	12	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	1	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	5	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	11	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	1	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	0
Georgia Power [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	8	5
Derivative Liability, Fair Value, Gross Liability	16	21
Georgia Power [Member] | Hedging Instruments for Regulatory Purposes [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	8	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	10	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	6	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	8	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	0	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	0
Gulf Power [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	12	7
Derivative Liability, Fair Value, Gross Liability	13	17
Gulf Power [Member] | Hedging Instruments for Regulatory Purposes [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	12	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	9	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	10	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	2	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	0
Mississippi Power [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	8	5
Derivative Liability, Fair Value, Gross Liability	8	10
Mississippi Power [Member] | Hedging Instruments for Regulatory Purposes [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	8	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	6	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	7	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	1	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	0
Southern Power [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	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	$ 0

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Condensed Consolidated Statements of Cash Flows (Unaudited) (Parenthetical) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Net cash paid for capitalized interest	$ 22,000	$ 17,000
Alabama Power [Member]
Net cash paid for capitalized interest	4,000	3,000
Georgia Power [Member]
Net cash paid for capitalized interest	3,000	3,000
Gulf Power [Member]
Net cash paid for capitalized interest	1,262	601
Mississippi Power [Member]
Interest paid	16,903	16,001
Net cash paid for capitalized interest	13,875	11,141
Southern Power [Member]
Net cash paid for capitalized interest	$ (113)	$ 0

XML

Fair Value Measurements - Fair Value Measurements Calculated at Net Asset Value Per Share (Details) (USD $)	3 Months Ended
	Mar. 31, 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	$ 131,000,000
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	131,000,000
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	65,000,000
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	65,000,000
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	45,000,000
Unfunded Commitments	0
Redemption Frequency	Daily/Monthly
Redemption Notice Period, Description	Daily/7 days
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	45,000,000
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	111,000,000
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	111,000,000
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	408,000,000
Unfunded Commitments	0
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
Fair Value	176,000,000
Unfunded Commitments	0
Redemption Frequency	Daily
Redemption Notice Period, Description	Not applicable
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	63,000,000
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	115,000,000
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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Derivatives (Policies)

3 Months Ended

Mar. 31, 2014

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Energy-Related Derivatives and Interest Rate Derivatives

Interest Rate Derivatives

Southern Company and certain subsidiaries may also enter into interest rate derivatives to hedge exposure to changes in interest rates. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings, with any ineffectiveness recorded directly to earnings. Derivatives related to existing fixed rate securities are accounted for as fair value hedges, where the derivatives' fair value gains or losses and hedged items' fair value gains or losses are both recorded directly to earnings, providing an offset, with any difference representing ineffectiveness.

Energy-Related Derivatives

The traditional operating companies and Southern Power enter into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the traditional operating companies have limited exposure to market volatility in commodity fuel prices and prices of electricity. Each of the traditional operating companies manages fuel-hedging programs, implemented per the guidelines of their respective state PSCs, through the use of financial derivative contracts, which is expected to continue to mitigate price volatility. The traditional operating companies (with respect to wholesale generating capacity) and Southern Power have limited exposure to market volatility in commodity fuel prices and prices of electricity because their long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, Southern Power has been and may continue to be exposed to market volatility in energy-related commodity prices as a result of uncontracted generating capacity. Further, the traditional operating companies may be 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.

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.

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 a cash flow hedge 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.

During the quarter ended March 31, 2014, Mississippi Power's fair value hedge was de-designated and the related ineffectiveness was recorded as a regulatory asset and was immaterial. At March 31, 2014, the fair value of the foreign currency derivatives outstanding was immaterial.

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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	Mar. 31, 2014
Long-term debt:
Long-term debt, Carrying Amount	$ 22,896
Long-term debt, Fair Value	23,963
Alabama Power [Member]
Long-term debt:
Long-term debt, Carrying Amount	6,228
Long-term debt, Fair Value	6,689
Georgia Power [Member]
Long-term debt:
Long-term debt, Carrying Amount	9,593
Long-term debt, Fair Value	9,997
Gulf Power [Member]
Long-term debt:
Long-term debt, Carrying Amount	1,233
Long-term debt, Fair Value	1,308
Mississippi Power [Member]
Long-term debt:
Long-term debt, Carrying Amount	2,346
Long-term debt, Fair Value	2,346
Southern Power [Member]
Long-term debt:
Long-term debt, Carrying Amount	1,620
Long-term debt, Fair Value	$ 1,709

XML

Fair Value Measurements (Tables)

3 Months Ended

Mar. 31, 2014

Fair Value Disclosures [Abstract]

Assets and liabilities measured at fair value on a recurring basis

As of March 31, 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 March 31, 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
Interest rate derivatives	3		—		—		3
Nuclear decommissioning trusts(a)	626		884		2		1,512
Cash equivalents	408		—		—		408
Other investments	9		—		4		13
Total	$	1,046	$	924	$	6	$	1,976
Liabilities:
Energy-related derivatives	$	—	$	43	$	—	$	43
Alabama Power
Assets:
Energy-related derivatives	$	—	$	12	$	—	$	12
Nuclear decommissioning trusts(b)
Domestic equity	403		77		—		480
Foreign equity	35		65		—		100
U.S. Treasury and government agency securities	—		29		—		29
Corporate bonds	—		88		—		88
Mortgage and asset backed securities	—		18		—		18
Other	—		9		2		11
Cash equivalents	176		—		—		176
Total	$	614	$	298	$	2	$	914
Liabilities:
Energy-related derivatives	$	—	$	6	$	—	$	6

	Fair Value Measurements Using
As of March 31, 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	$	—	$	8	$	—	$	8
Nuclear decommissioning trusts(b) (c)
Domestic equity	188		1		—		189
Foreign equity	—		131		—		131
U.S. Treasury and government agency securities	—		125		—		125
Municipal bonds	—		40		—		40
Corporate bonds	—		153		—		153
Mortgage and asset backed securities	—		103		—		103
Other	—		45		—		45
Total	$	188	$	606	$	—	$	794
Liabilities:
Energy-related derivatives	$	—	$	16	$	—	$	16
Gulf Power
Assets:
Energy-related derivatives	$	—	$	12	$	—	$	12
Cash equivalents	18		—		—		18
Total	$	18	$	12	$	—	$	30
Liabilities:
Energy-related derivatives	$	—	$	13	$	—	$	13
Mississippi Power
Assets:
Energy-related derivatives	$	—	$	8	$	—	$	8
Cash equivalents	63		—		—		63
Total	$	63	$	8	$	—	$	71
Liabilities:
Energy-related derivatives	$	—	$	8	$	—	$	8
Southern Power
Assets:
Cash equivalents	$	115	$	—	$	—	$	115

(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 March 31, 2014, approximately $51 million of the fair market value of Georgia Power's nuclear decommissioning trust funds' securities were on loan and pledged to creditors under the funds' managers' securities lending program.

Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments

As of March 31, 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 March 31, 2014:	Fair Value		Unfunded Commitments	Redemption Frequency	Redemption Notice Period
	(in millions)
Southern Company
Nuclear decommissioning trusts:
Foreign equity funds	$	131	None	Monthly	5 days
Equity - commingled funds	65		None	Daily/Monthly	Daily/7 days
Other - commingled funds	45		None	Daily/Monthly	Daily/7 days
Trust-owned life insurance	111		None	Daily	15 days
Cash equivalents:
Money market funds	408		None	Daily	Not applicable
Alabama Power
Nuclear decommissioning trusts:
Equity - commingled funds	$	65	None	Daily/Monthly	Daily/7 days
Trust-owned life insurance	111		None	Daily	15 days
Cash equivalents:
Money market funds	176		None	Daily	Not applicable
Georgia Power
Nuclear decommissioning trusts:
Foreign equity funds	$	131	None	Monthly	5 days
Other - commingled funds	45		None	Daily	Not applicable
Gulf Power
Cash equivalents:
Money market funds	$	18	None	Daily	Not applicable
Mississippi Power
Cash equivalents:
Money market funds	$	63	None	Daily	Not applicable
Southern Power
Cash equivalents:
Money market funds	$	115	None	Daily	Not applicable

Financial instruments for which carrying amount did not equal fair value

As of March 31, 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	$	22,896	$	23,963
Alabama Power	$	6,228	$	6,689
Georgia Power	$	9,593	$	9,997
Gulf Power	$	1,233	$	1,308
Mississippi Power	$	2,346	$	2,346
Southern Power	$	1,620	$	1,709

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Condensed Consolidated Balance Sheets (Unaudited) (USD $)	Mar. 31, 2014	Dec. 31, 2013
Current Assets:
Cash and cash equivalents	$ 590,000,000	$ 659,000,000
Receivables --
Customer accounts receivable	1,063,000,000	1,027,000,000
Unbilled revenues	382,000,000	448,000,000
Under recovered regulatory clause revenues	72,000,000	58,000,000
Other accounts and notes receivable	306,000,000	304,000,000
Accumulated provision for uncollectible accounts	(17,000,000)	(18,000,000)
Fossil fuel stock, at average cost	898,000,000	1,339,000,000
Materials and supplies, at average cost	963,000,000	959,000,000
Vacation pay	171,000,000	171,000,000
Prepaid expenses	525,000,000	489,000,000
Other regulatory assets, current	117,000,000	124,000,000
Other current assets	70,000,000	39,000,000
Total current assets	5,140,000,000	5,599,000,000
Property, Plant, and Equipment:
In service	66,369,000,000	66,021,000,000
Less accumulated provision for depreciation	23,329,000,000	23,059,000,000
Plant in service, net of depreciation	43,040,000,000	42,962,000,000
Other utility plant, net	234,000,000	240,000,000
Nuclear fuel, at amortized cost	874,000,000	855,000,000
Construction work in progress	7,425,000,000	7,151,000,000
Total property, plant, and equipment	51,573,000,000	51,208,000,000
Other Property and Investments:
Nuclear decommissioning trusts, at fair value	1,513,000,000	1,465,000,000
Leveraged leases	670,000,000	665,000,000
Miscellaneous property and investments	224,000,000	218,000,000
Total other property and investments	2,407,000,000	2,348,000,000
Deferred Charges and Other Assets:
Deferred charges related to income taxes	1,448,000,000	1,432,000,000
Prepaid pension costs	423,000,000	419,000,000
Unamortized debt issuance expense	202,000,000	139,000,000
Unamortized loss on reacquired debt	286,000,000	293,000,000
Other regulatory assets, deferred	2,654,000,000	2,557,000,000
Other deferred charges and assets	705,000,000	551,000,000
Total deferred charges and other assets	5,718,000,000	5,391,000,000
Total Assets	64,838,000,000	64,546,000,000
Current Liabilities:
Securities due within one year	768,000,000	469,000,000
Interest-bearing refundable deposit related to asset sale	225,000,000	150,000,000
Notes payable	598,000,000	1,482,000,000
Other accounts payable	1,386,000,000	1,376,000,000
Customer deposits	384,000,000	380,000,000
Accrued taxes --
Accrued income taxes	114,000,000	13,000,000
Other accrued taxes	243,000,000	456,000,000
Accrued interest	253,000,000	251,000,000
Accrued vacation pay	213,000,000	217,000,000
Accrued compensation	177,000,000	303,000,000
Other regulatory liabilities, current	116,000,000	92,000,000
Other current liabilities	358,000,000	347,000,000
Total current liabilities	4,835,000,000	5,536,000,000
Long-term Debt	22,288,000,000	21,344,000,000
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	10,558,000,000	10,563,000,000
Deferred credits related to income taxes	197,000,000	202,000,000
Accumulated deferred investment tax credits	962,000,000	966,000,000
Employee benefit obligations	1,446,000,000	1,461,000,000
Asset retirement obligations	2,004,000,000	2,006,000,000
Other cost of removal obligations	1,298,000,000	1,270,000,000
Other regulatory liabilities, deferred	481,000,000	475,000,000
Other deferred credits and liabilities	568,000,000	584,000,000
Total deferred credits and other liabilities	17,514,000,000	17,527,000,000
Total Liabilities	44,637,000,000	44,407,000,000
Redeemable Preferred Stock of Subsidiaries	375,000,000	375,000,000
Common Stockholders' Equity:
Common stock	4,467,000,000	4,461,000,000
Paid-in capital	5,405,000,000	5,362,000,000
Treasury, at cost	(139,000,000)	(250,000,000)
Retained earnings	9,410,000,000	9,510,000,000
Accumulated other comprehensive loss	(73,000,000)	(75,000,000)
Total common stockholders' equity	19,070,000,000	19,008,000,000
Preferred and Preference Stock of Subsidiaries	756,000,000	756,000,000
Total Stockholders' Equity	19,826,000,000	19,764,000,000
Total Liabilities and Stockholders' Equity	64,838,000,000	64,546,000,000
Alabama Power [Member]
Current Assets:
Cash and cash equivalents	252,000,000	295,000,000
Receivables --
Customer accounts receivable	363,000,000	341,000,000
Unbilled revenues	116,000,000	142,000,000
Other accounts and notes receivable	33,000,000	30,000,000
Affiliated companies	63,000,000	54,000,000
Accumulated provision for uncollectible accounts	(8,000,000)	(8,000,000)
Fossil fuel stock, at average cost	230,000,000	329,000,000
Materials and supplies, at average cost	373,000,000	375,000,000
Vacation pay	63,000,000	63,000,000
Prepaid expenses	146,000,000	57,000,000
Other regulatory assets, current	5,000,000	7,000,000
Other current assets	13,000,000	6,000,000
Total current assets	1,649,000,000	1,691,000,000
Property, Plant, and Equipment:
In service	22,234,000,000	22,092,000,000
Less accumulated provision for depreciation	8,226,000,000	8,114,000,000
Plant in service, net of depreciation	14,008,000,000	13,978,000,000
Nuclear fuel, at amortized cost	342,000,000	332,000,000
Construction work in progress	829,000,000	748,000,000
Total property, plant, and equipment	15,179,000,000	15,058,000,000
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	56,000,000	54,000,000
Nuclear decommissioning trusts, at fair value	727,000,000	714,000,000
Miscellaneous property and investments	81,000,000	80,000,000
Total other property and investments	864,000,000	848,000,000
Deferred Charges and Other Assets:
Deferred charges related to income taxes	522,000,000	519,000,000
Prepaid pension costs	279,000,000	276,000,000
Deferred under recovered regulatory clause revenues	36,000,000	25,000,000
Other regulatory assets, deferred	707,000,000	692,000,000
Other deferred charges and assets	126,000,000	142,000,000
Total deferred charges and other assets	1,670,000,000	1,654,000,000
Total Assets	19,362,000,000	19,251,000,000
Current Liabilities:
Affiliated accounts payable	191,000,000	198,000,000
Other accounts payable	259,000,000	339,000,000
Customer deposits	86,000,000	85,000,000
Accrued taxes --
Accrued income taxes	137,000,000	11,000,000
Other accrued taxes	57,000,000	33,000,000
Accrued interest	58,000,000	61,000,000
Accrued vacation pay	53,000,000	53,000,000
Accrued compensation	40,000,000	74,000,000
Other regulatory liabilities, current	36,000,000	37,000,000
Other current liabilities	39,000,000	41,000,000
Total current liabilities	956,000,000	932,000,000
Long-term Debt	6,233,000,000	6,233,000,000
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	3,623,000,000	3,603,000,000
Deferred credits related to income taxes	74,000,000	75,000,000
Accumulated deferred investment tax credits	131,000,000	133,000,000
Employee benefit obligations	193,000,000	195,000,000
Asset retirement obligations	741,000,000	730,000,000
Other cost of removal obligations	843,000,000	828,000,000
Other regulatory liabilities, deferred	255,000,000	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	5,925,000,000	5,899,000,000
Total Liabilities	13,114,000,000	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	2,273,000,000	2,262,000,000
Retained earnings	2,093,000,000	2,044,000,000
Accumulated other comprehensive loss	(25,000,000)	(26,000,000)
Total common stockholders' equity	5,563,000,000	5,502,000,000
Total Liabilities and Stockholders' Equity	19,362,000,000	19,251,000,000
Georgia Power [Member]
Current Assets:
Cash and cash equivalents	18,000,000	30,000,000
Receivables --
Customer accounts receivable	523,000,000	512,000,000
Unbilled revenues	179,000,000	209,000,000
Joint owner accounts receivable	85,000,000	67,000,000
Other accounts and notes receivable	69,000,000	117,000,000
Affiliated companies	21,000,000	21,000,000
Accumulated provision for uncollectible accounts	(5,000,000)	(5,000,000)
Fossil fuel stock, at average cost	486,000,000	742,000,000
Materials and supplies, at average cost	409,000,000	409,000,000
Vacation pay	88,000,000	88,000,000
Prepaid income taxes	103,000,000	97,000,000
Other regulatory assets, current	61,000,000	66,000,000
Other current assets	108,000,000	54,000,000
Total current assets	2,145,000,000	2,407,000,000
Property, Plant, and Equipment:
In service	30,295,000,000	30,132,000,000
Less accumulated provision for depreciation	11,028,000,000	10,970,000,000
Plant in service, net of depreciation	19,267,000,000	19,162,000,000
Other utility plant, net	234,000,000	240,000,000
Nuclear fuel, at amortized cost	532,000,000	523,000,000
Construction work in progress	3,660,000,000	3,500,000,000
Total property, plant, and equipment	23,693,000,000	23,425,000,000
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	47,000,000	46,000,000
Nuclear decommissioning trusts, at fair value	786,000,000	751,000,000
Miscellaneous property and investments	43,000,000	44,000,000
Total other property and investments	876,000,000	841,000,000
Deferred Charges and Other Assets:
Deferred charges related to income taxes	710,000,000	718,000,000
Prepaid pension costs	123,000,000	118,000,000
Deferred under recovered regulatory clause revenues	152,000,000	0
Other regulatory assets, deferred	1,207,000,000	1,152,000,000
Other deferred charges and assets	283,000,000	246,000,000
Total deferred charges and other assets	2,475,000,000	2,234,000,000
Total Assets	29,189,000,000	28,907,000,000
Current Liabilities:
Securities due within one year	5,000,000	5,000,000
Notes payable	298,000,000	1,047,000,000
Affiliated accounts payable	440,000,000	417,000,000
Other accounts payable	514,000,000	472,000,000
Customer deposits	249,000,000	246,000,000
Accrued taxes --
Accrued income taxes	30,000,000	0
Other accrued taxes	123,000,000	321,000,000
Accrued interest	98,000,000	91,000,000
Accrued vacation pay	60,000,000	61,000,000
Accrued compensation	51,000,000	80,000,000
Liabilities from risk management activities	10,000,000	13,000,000
Nuclear decommissioning trust securities lending collateral	36,000,000	9,000,000
Other regulatory liabilities, current	22,000,000	17,000,000
Other current liabilities	160,000,000	127,000,000
Total current liabilities	2,096,000,000	2,906,000,000
Long-term Debt	9,632,000,000	8,633,000,000
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	5,288,000,000	5,200,000,000
Deferred credits related to income taxes	110,000,000	112,000,000
Accumulated deferred investment tax credits	200,000,000	203,000,000
Employee benefit obligations	541,000,000	542,000,000
Asset retirement obligations	1,196,000,000	1,210,000,000
Other cost of removal obligations	53,000,000	43,000,000
Other deferred credits and liabilities	172,000,000	201,000,000
Total deferred credits and other liabilities	7,560,000,000	7,511,000,000
Total Liabilities	19,288,000,000	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	5,651,000,000	5,633,000,000
Retained earnings	3,591,000,000	3,565,000,000
Accumulated other comprehensive loss	(5,000,000)	(5,000,000)
Total common stockholders' equity	9,635,000,000	9,591,000,000
Total Liabilities and Stockholders' Equity	29,189,000,000	28,907,000,000
Gulf Power [Member]
Current Assets:
Cash and cash equivalents	23,356,000	21,753,000
Receivables --
Customer accounts receivable	70,386,000	64,884,000
Unbilled revenues	50,447,000	57,282,000
Under recovered regulatory clause revenues	62,169,000	48,282,000
Other accounts and notes receivable	11,421,000	8,620,000
Affiliated companies	18,147,000	8,259,000
Accumulated provision for uncollectible accounts	(995,000)	(1,131,000)
Fossil fuel stock, at average cost	88,783,000	135,050,000
Materials and supplies, at average cost	55,102,000	54,935,000
Prepaid expenses	11,602,000	33,186,000
Other regulatory assets, current	16,722,000	18,536,000
Other current assets	12,206,000	6,120,000
Total current assets	419,346,000	455,776,000
Property, Plant, and Equipment:
In service	4,390,454,000	4,363,664,000
Less accumulated provision for depreciation	1,232,745,000	1,211,336,000
Plant in service, net of depreciation	3,157,709,000	3,152,328,000
Construction work in progress	325,001,000	280,626,000
Total property, plant, and equipment	3,482,710,000	3,432,954,000
Other Property and Investments:
Total other property and investments	15,119,000	15,314,000
Deferred Charges and Other Assets:
Deferred charges related to income taxes	52,017,000	50,597,000
Prepaid pension costs	11,569,000	11,533,000
Other regulatory assets, deferred	345,956,000	340,415,000
Other deferred charges and assets	33,006,000	30,982,000
Total deferred charges and other assets	442,548,000	433,527,000
Total Assets	4,359,723,000	4,337,571,000
Current Liabilities:
Securities due within one year	75,000,000	75,000,000
Notes payable	60,489,000	135,878,000
Affiliated accounts payable	88,507,000	76,897,000
Other accounts payable	42,814,000	47,038,000
Customer deposits	34,508,000	34,433,000
Accrued taxes --
Accrued income taxes	5,166,000	45,000
Other accrued taxes	13,031,000	7,486,000
Accrued interest	17,959,000	10,272,000
Accrued compensation	6,856,000	11,657,000
Liabilities from risk management activities	3,804,000	6,470,000
Other regulatory liabilities, current	19,283,000	13,408,000
Other current liabilities	22,537,000	22,972,000
Total current liabilities	389,954,000	441,556,000
Long-term Debt	1,158,305,000	1,158,163,000
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	743,992,000	734,355,000
Accumulated deferred investment tax credits	3,737,000	4,055,000
Employee benefit obligations	76,549,000	76,338,000
Other cost of removal obligations	225,580,000	228,148,000
Other regulatory liabilities, deferred	54,935,000	56,051,000
Deferred capacity expense	190,795,000	180,149,000
Other deferred credits and liabilities	76,793,000	77,126,000
Total deferred credits and other liabilities	1,372,381,000	1,356,222,000
Total Liabilities	2,920,640,000	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	554,098,000	552,681,000
Retained earnings	256,437,000	250,494,000
Accumulated other comprehensive loss	(1,016,000)	(1,109,000)
Total common stockholders' equity	1,292,579,000	1,235,126,000
Total Liabilities and Stockholders' Equity	4,359,723,000	4,337,571,000
Mississippi Power [Member]
Current Assets:
Cash and cash equivalents	85,182,000	145,165,000
Receivables --
Customer accounts receivable	40,722,000	40,978,000
Unbilled revenues	37,363,000	38,895,000
Under recovered regulatory clause revenues	2,146,000	0
Other accounts and notes receivable	3,853,000	4,600,000
Affiliated companies	48,835,000	34,920,000
Accumulated provision for uncollectible accounts	(2,113,000)	(3,018,000)
Fossil fuel stock, at average cost	76,689,000	113,285,000
Materials and supplies, at average cost	48,317,000	45,347,000
Prepaid income taxes	60,355,000	34,751,000
Other regulatory assets, current	53,416,000	52,496,000
Other current assets	13,525,000	9,357,000
Total current assets	468,290,000	516,776,000
Property, Plant, and Equipment:
In service	3,467,314,000	3,458,770,000
Less accumulated provision for depreciation	1,108,649,000	1,095,352,000
Plant in service, net of depreciation	2,358,665,000	2,363,418,000
Construction work in progress	2,550,361,000	2,586,031,000
Total property, plant, and equipment	4,909,026,000	4,949,449,000
Other Property and Investments:
Total other property and investments	4,909,000	4,857,000
Deferred Charges and Other Assets:
Deferred charges related to income taxes	158,788,000	139,834,000
Other regulatory assets, deferred	212,467,000	200,620,000
Accumulated deferred income taxes	34,533,000	0
Other deferred charges and assets	39,899,000	36,673,000
Total deferred charges and other assets	445,687,000	377,127,000
Total Assets	5,827,912,000	5,848,209,000
Current Liabilities:
Securities due within one year	313,821,000	13,789,000
Interest-bearing refundable deposit related to asset sale	225,000,000	150,000,000
Affiliated accounts payable	74,332,000	70,299,000
Other accounts payable	190,538,000	210,191,000
Customer deposits	14,867,000	14,379,000
Accrued taxes --
Accrued income taxes	3,222,000	5,590,000
Other accrued taxes	26,020,000	77,958,000
Accrued interest	55,369,000	47,144,000
Accrued compensation	7,244,000	9,324,000
Other regulatory liabilities, current	38,316,000	24,981,000
Over recovered regulatory clause liabilities	0	18,358,000
Other current liabilities	19,767,000	21,413,000
Total current liabilities	968,496,000	663,426,000
Long-term Debt	2,114,184,000	2,167,067,000
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	0	72,808,000
Deferred credits related to income taxes	7,873,000	9,145,000
Accumulated deferred investment tax credits	283,959,000	284,248,000
Employee benefit obligations	94,116,000	94,430,000
Asset retirement obligations	41,682,000	41,197,000
Other cost of removal obligations	156,426,000	151,340,000
Other regulatory liabilities, deferred	162,997,000	140,880,000
Other deferred credits and liabilities	14,128,000	14,337,000
Total deferred credits and other liabilities	761,181,000	808,385,000
Total Liabilities	3,843,861,000	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	2,323,151,000	2,376,595,000
Retained earnings	(401,919,000)	(229,871,000)
Accumulated other comprehensive loss	(7,652,000)	(7,864,000)
Total common stockholders' equity	1,951,271,000	2,176,551,000
Total Liabilities and Stockholders' Equity	5,827,912,000	5,848,209,000
Southern Power [Member]
Current Assets:
Cash and cash equivalents	129,151,000	68,744,000
Receivables --
Customer accounts receivable	69,757,000	73,497,000
Other accounts and notes receivable	3,901,000	3,983,000
Affiliated companies	21,343,000	38,391,000
Fossil fuel stock, at average cost	16,920,000	19,178,000
Materials and supplies, at average cost	57,542,000	54,780,000
Prepaid service agreements - current	65,321,000	81,206,000
Prepaid income taxes	24,237,000	54,732,000
Prepaid expenses	5,715,000	7,915,000
Assets from risk management activities	231,000	182,000
Total current assets	394,118,000	402,608,000
Property, Plant, and Equipment:
In service	4,705,764,000	4,696,134,000
Less accumulated provision for depreciation	928,641,000	871,963,000
Plant in service, net of depreciation	3,777,123,000	3,824,171,000
Construction work in progress	10,926,000	9,843,000
Total property, plant, and equipment	3,788,049,000	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	42,887,000	43,505,000
Total other property and investments	44,726,000	45,344,000
Deferred Charges and Other Assets:
Prepaid long-term service agreements	96,550,000	73,676,000
Other deferred charges and assets -- affiliated	7,813,000	4,605,000
Other deferred charges and assets	72,564,000	68,853,000
Total deferred charges and other assets	176,927,000	147,134,000
Total Assets	4,403,820,000	4,429,100,000
Current Liabilities:
Securities due within one year	1,412,000	599,000
Affiliated accounts payable	61,270,000	56,661,000
Other accounts payable	20,469,000	20,747,000
Accrued taxes --
Accrued income taxes	2,304,000	161,000
Other accrued taxes	6,350,000	2,662,000
Accrued interest	13,850,000	28,352,000
Deferred capacity revenues — current affiliated	1,536,000	4,229,000
Other current liabilities	12,863,000	14,263,000
Total current liabilities	120,054,000	127,674,000
Long-term Debt	1,618,263,000	1,619,241,000
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	717,033,000	724,390,000
Deferred convertible investment tax credits	341,702,000	340,269,000
Deferred capacity revenues -- affiliated	5,297,000	15,279,000
Other deferred credits and liabilities — affiliated	1,367,000	1,621,000
Other deferred credits and liabilities	8,211,000	7,896,000
Total deferred credits and other liabilities	1,073,610,000	1,089,455,000
Total Liabilities	2,811,927,000	2,836,370,000
Redeemable Noncontrolling Interest	29,914,000	28,778,000
Common Stockholders' Equity:
Common stock	0	0
Paid-in capital	1,026,283,000	1,029,035,000
Retained earnings	532,690,000	531,998,000
Accumulated other comprehensive loss	3,006,000	2,919,000
Total common stockholders' equity	1,561,979,000	1,563,952,000
Total Liabilities and Stockholders' Equity	$ 4,403,820,000	$ 4,429,100,000

XML

Condensed Consolidated Statements of Comprehensive Income (Unaudited) (USD $)	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Net Income	$ 368,000,000	$ 97,000,000
Qualifying hedges:
Reclassification adjustment for amounts included in net income, net of tax	1,000,000	3,000,000
Pension and other post retirement benefit plans:
Reclassification adjustment for amounts included in net income, net of tax	1,000,000	1,000,000
Total other comprehensive income (loss)	2,000,000	4,000,000
Less: Comprehensive income attributable to noncontrolling interest	17,000,000	16,000,000
Comprehensive Income	353,000,000	85,000,000
Alabama Power [Member]
Net Income	197,000,000	151,000,000
Qualifying hedges:
Changes in fair value, net of tax	0	0
Pension and other post retirement benefit plans:
Total other comprehensive income (loss)	0	0
Comprehensive Income	197,000,000	151,000,000
Georgia Power [Member]
Net Income	270,000,000	201,000,000
Qualifying hedges:
Reclassification adjustment for amounts included in net income, net of tax	0	1,000,000
Pension and other post retirement benefit plans:
Total other comprehensive income (loss)	0	1,000,000
Comprehensive Income	270,000,000	202,000,000
Gulf Power [Member]
Net Income	38,994,000	23,343,000
Qualifying hedges:
Reclassification adjustment for amounts included in net income, net of tax	93,000	143,000
Pension and other post retirement benefit plans:
Total other comprehensive income (loss)	93,000	143,000
Comprehensive Income	39,087,000	23,486,000
Mississippi Power [Member]
Net Income	(171,615,000)	(245,888,000)
Qualifying hedges:
Changes in fair value, net of tax	(1,000)	0
Reclassification adjustment for amounts included in net income, net of tax	212,000	212,000
Pension and other post retirement benefit plans:
Total other comprehensive income (loss)	211,000	212,000
Comprehensive Income	(171,404,000)	(245,676,000)
Southern Power [Member]
Net Income	34,287,000	29,192,000
Qualifying hedges:
Changes in fair value, net of tax	(2,000)	0
Reclassification adjustment for amounts included in net income, net of tax	89,000	1,634,000
Pension and other post retirement benefit plans:
Total other comprehensive income (loss)	87,000	1,634,000
Less: Comprehensive income attributable to noncontrolling interest	816,000	0
Comprehensive Income	$ 33,558,000	$ 30,826,000

XML

Acquisitions

3 Months Ended

Mar. 31, 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 is expected to begin commercial operation in May 2014. The output of the plant is contracted under a 20-year PPA with Southern California Edison Company, which will begin on the commercial operation date. The acquisition is in accordance with Southern Power's overall growth strategy.

Southern Power's acquisition of Adobe included cash consideration of approximately $94.4 million, of which $75.5 million was paid at closing, with the remainder to be paid upon completion of certain milestones. The allocation of purchase price to individual assets has not been finalized. As of the acquisition date, approximately $81 million was allocated to CWIP and the remainder to other assets. The acquisition did not include any contingent consideration and due diligence costs were expensed as incurred and were not material.

XML

Document and Entity Information	3 Months Ended
	Mar. 31, 2014
Entity Information [Line Items]
Entity Registrant Name	SOUTHERN CO
Entity Central Index Key	0000092122
Document Type	10-Q
Document Period End Date	Mar. 31, 2014
Amendment Flag	false
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	Q1
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding	890,811,428
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

3 Months Ended

Mar. 31, 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 $72 million and $78 million for the three months ended March 31, 2014 and March 31, 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 months ended March 31, 2014 and 2013 was as follows:

	Electric Utilities
	Traditional Operating Companies		Southern Power		Eliminations			Total		All Other			Eliminations			Consolidated
	(in millions)
Three Months Ended March 31, 2014:
Operating revenues	$	4,378	$	351	$	(102	)	$	4,627	$	41		$	(24	)	$	4,644
Segment net income (loss)(a)(b)	318		33		—			351		—			—			351
Total assets at March 31, 2014	$	59,854	$	4,404	$	(98	)	$	64,160	$	1,093		$	(415	)	$	64,838
Three Months Ended March 31, 2013:
Operating revenues	$	3,668	$	303	$	(86	)	$	3,885	$	35		$	(23	)	$	3,897
Segment net income (loss)(a)(c)	66		29		—			95		(16		)	2			81
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 March 31, 2014 includes a $380.0 million pre-tax charge ($234.7 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 three months ended March 31, 2013 includes $540.0 million in pre-tax charges ($333.5 million after tax) for estimated probable losses on the Kemper IGCC. See Note (B) under "Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" herein for additional information.

Products and Services

	Electric Utilities' Revenues
Period	Retail		Wholesale		Other		Total
	(in millions)
Three Months Ended March 31, 2014	$	3,858	$	604	$	165	$	4,627
Three Months Ended March 31, 2013	3,298		432		155		3,885

XML

Condensed Consolidated Statements of Comprehensive Income (Unaudited) (Parenthetical) (USD $)	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Reclassification adjustment for amounts of qualifying hedges included in net income, tax	$ 1,000,000	$ 2,000,000
Reclassification adjustment for amounts of pension and other post retirement benefit plans included in net income, tax	0	1,000,000
Alabama Power [Member]
Changes in fair value, tax	0	0
Georgia Power [Member]
Reclassification adjustment for amounts of qualifying hedges included in net income, tax	0	0
Gulf Power [Member]
Reclassification adjustment for amounts of qualifying hedges included in net income, tax	58,000	90,000
Mississippi Power [Member]
Changes in fair value, tax	(1,000)	0
Reclassification adjustment for amounts of qualifying hedges included in net income, tax	131,000	131,000
Southern Power [Member]
Changes in fair value, tax	(1,000)	0
Reclassification adjustment for amounts of qualifying hedges included in net income, tax	$ 39,000	$ 1,045,000

XML

Stockholders' Equity

3 Months Ended

Mar. 31, 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 March 31, 2014	Three Months Ended March 31, 2013
	(in millions)
As reported shares	890	870
Effect of options and performance share award units	3	5
Diluted shares	893	875

Stock options and performance share award units that were not included in the diluted earnings per share calculation because they were anti-dilutive were 17 million for the three months ended March 31, 2014 and were immaterial for the three months ended March 31, 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	—	—		351			—		351
Other comprehensive income (loss)	—	—		2			—		2
Treasury stock re-issued	—	2,404		111			—		111
Stock issued	1,340	—		53			—		53
Stock repurchased, at cost	—	—		(4		)	—		(4		)
Cash dividends on common stock	—	—		(451		)	—		(451		)
Other	—	(18	)	—			—		—
Balance at March 31, 2014	894,073	(3,261	)	$	19,070		$	756	$	19,826
Balance at December 31, 2012	877,803	(10,035	)	$	18,297		$	707	$	19,004
Net income after dividends on preferred and preference stock	—	—		81			—		81
Other comprehensive income (loss)	—	—		4			—		4
Stock issued	2,638	—		99			—		99
Stock repurchased, at cost	—	—		(18		)	—		(18		)
Cash dividends on common stock	—	—		(426		)	—		(426		)
Other	—	(15	)	—			—		—
Balance at March 31, 2013	880,441	(10,050	)	$	18,037		$	707	$	18,744

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Fair Value Measurements

3 Months Ended

Mar. 31, 2014

Fair Value Disclosures [Abstract]

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS

As of March 31, 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 March 31, 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
Interest rate derivatives	3		—		—		3
Nuclear decommissioning trusts(a)	626		884		2		1,512
Cash equivalents	408		—		—		408
Other investments	9		—		4		13
Total	$	1,046	$	924	$	6	$	1,976
Liabilities:
Energy-related derivatives	$	—	$	43	$	—	$	43
Alabama Power
Assets:
Energy-related derivatives	$	—	$	12	$	—	$	12
Nuclear decommissioning trusts(b)
Domestic equity	403		77		—		480
Foreign equity	35		65		—		100
U.S. Treasury and government agency securities	—		29		—		29
Corporate bonds	—		88		—		88
Mortgage and asset backed securities	—		18		—		18
Other	—		9		2		11
Cash equivalents	176		—		—		176
Total	$	614	$	298	$	2	$	914
Liabilities:
Energy-related derivatives	$	—	$	6	$	—	$	6

	Fair Value Measurements Using
As of March 31, 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	$	—	$	8	$	—	$	8
Nuclear decommissioning trusts(b) (c)
Domestic equity	188		1		—		189
Foreign equity	—		131		—		131
U.S. Treasury and government agency securities	—		125		—		125
Municipal bonds	—		40		—		40
Corporate bonds	—		153		—		153
Mortgage and asset backed securities	—		103		—		103
Other	—		45		—		45
Total	$	188	$	606	$	—	$	794
Liabilities:
Energy-related derivatives	$	—	$	16	$	—	$	16
Gulf Power
Assets:
Energy-related derivatives	$	—	$	12	$	—	$	12
Cash equivalents	18		—		—		18
Total	$	18	$	12	$	—	$	30
Liabilities:
Energy-related derivatives	$	—	$	13	$	—	$	13
Mississippi Power
Assets:
Energy-related derivatives	$	—	$	8	$	—	$	8
Cash equivalents	63		—		—		63
Total	$	63	$	8	$	—	$	71
Liabilities:
Energy-related derivatives	$	—	$	8	$	—	$	8
Southern Power
Assets:
Cash equivalents	$	115	$	—	$	—	$	115

(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 March 31, 2014, approximately $51 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.

"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 March 31, 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 March 31, 2014:	Fair Value		Unfunded Commitments	Redemption Frequency	Redemption Notice Period
	(in millions)
Southern Company
Nuclear decommissioning trusts:
Foreign equity funds	$	131	None	Monthly	5 days
Equity - commingled funds	65		None	Daily/Monthly	Daily/7 days
Other - commingled funds	45		None	Daily/Monthly	Daily/7 days
Trust-owned life insurance	111		None	Daily	15 days
Cash equivalents:
Money market funds	408		None	Daily	Not applicable
Alabama Power
Nuclear decommissioning trusts:
Equity - commingled funds	$	65	None	Daily/Monthly	Daily/7 days
Trust-owned life insurance	111		None	Daily	15 days
Cash equivalents:
Money market funds	176		None	Daily	Not applicable
Georgia Power
Nuclear decommissioning trusts:
Foreign equity funds	$	131	None	Monthly	5 days
Other - commingled funds	45		None	Daily	Not applicable
Gulf Power
Cash equivalents:
Money market funds	$	18	None	Daily	Not applicable
Mississippi Power
Cash equivalents:
Money market funds	$	63	None	Daily	Not applicable
Southern Power
Cash equivalents:
Money market funds	$	115	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 March 31, 2014 is $7 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. 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 months ended March 31, 2014, the change in fair value of the funds, including reinvested interest and dividends reduced by the funds' expenses, increased by $27 million at Southern Company. Alabama Power recorded an increase in fair value of $16 million as an increase in regulatory liabilities. Georgia Power recorded an increase in fair value of $11 million 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 March 31, 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	$	22,896	$	23,963
Alabama Power	$	6,228	$	6,689
Georgia Power	$	9,593	$	9,997
Gulf Power	$	1,233	$	1,308
Mississippi Power	$	2,346	$	2,346
Southern Power	$	1,620	$	1,709

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.

XML

Contingencies and Regulatory Matters Contingencies and Regulatory Matters (Tables)

3 Months Ended

Mar. 31, 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	March 31, 2014		December 31, 2013
		(in millions)
Rate CNP Environmental – Under	Deferred under recovered regulatory clause revenues	$	13	$	7
Rate CNP PPA – Under	Deferred under recovered regulatory clause revenues	23		18
Retail Energy Cost Recovery – Over	Other regulatory liabilities, current	22		27
	Deferred over recovered regulatory clause revenues	—		15
Natural Disaster Reserve	Other regulatory liabilities, deferred	91		96

Recovery Position of Each Regulatory Clause

The recovery balance of each regulatory clause follows:

Recovery Clause	Balance Sheet Location	March 31, 2014		December 31, 2013
		(in millions)
Fuel Cost Recovery – Under	Under recovered regulatory clause revenues	$	35.7	$	21.0
Purchased Power Capacity Recovery – Over	Other regulatory liabilities, current	5.5		—
Purchased Power Capacity Recovery – Under	Under recovered regulatory clause revenues	—		2.8
Environmental Cost Recovery – Under	Under recovered regulatory clause revenues	17.1		14.4
Energy Conservation Cost Recovery – Under	Under recovered regulatory clause revenues	6.3		7.0

Current And Actual Cost Estimate for Kemper IGC

Mississippi Power's 2010 project estimate, current cost estimate, and actual costs incurred as of March 31, 2014 for the Kemper IGCC are as follows:

Cost Category	2010 Project Estimate(e)		Current Estimate		Actual Costs at March 31, 2014
	(in billions)
Plant Subject to Cost Cap(a)	$	2.40	$	4.44	$	3.52
Lignite Mine and Equipment	0.21		0.23		0.23
CO2 Pipeline Facilities	0.14		0.11		0.10
AFUDC(b)(c)	0.17		0.55		0.32
General Exceptions	0.05		0.10		0.07
Regulatory Asset(c)(d)	—		0.10		0.08
Total Kemper IGCC(a)(c)	$	2.97	$	5.53	$	4.32

(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.

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Introduction (Policies)

3 Months Ended

Mar. 31, 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 quarter 2014 and is not expected to have a material impact on the financial statements of Southern Company or Southern Power in future periods.

XML

Effective Tax Rate

3 Months Ended

Mar. 31, 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 32.3% for the three months ended March 31, 2014 compared to 24.5% 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, state income tax credits, and beneficial changes in certain state income tax laws.

Alabama Power

Alabama Power's effective tax rate was 39.3% for the three months ended March 31, 2014 compared to 39.2% for the corresponding period in 2013.

Georgia Power

Georgia Power's effective tax rate was 38.0% for the three months ended March 31, 2014 compared to 38.1% for the corresponding period in 2013.

Gulf Power

Gulf Power's effective tax rate was 37.4% for the three months ended March 31, 2014 compared to 37.6% for the corresponding period in 2013.

Mississippi Power

Mississippi Power's effective tax rate was (43.0)% for the three months ended March 31, 2014 compared to (40.8)% for the corresponding period in 2013. The decrease 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 8.5% for the three months ended March 31, 2014 compared to 33.5% for the corresponding period in 2013. The decrease was primarily due to an increase in state tax credits and beneficial changes in certain state income tax laws.

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Financing

3 Months Ended

Mar. 31, 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 March 31, 2014 was approximately $1.8 billion. In addition, at March 31, 2014, the traditional operating companies had $559 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 March 31, 2014:

	Expires(a)												Executable Term Loans				Due Within One Year
Company	2014		2015		2016		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	238		35		—		1,030		1,303		1,303		53		—		53		185
Georgia Power	—		—		150		1,600		1,750		1,736		—		—		—		—
Gulf Power	75		35		165		—		275		275		50		—		50		60
Mississippi Power	135		—		165		—		300		300		25		40		65		70
Southern Power	—		—		—		500		500		500		—		—		—		—
Other	75		25		—		—		100		100		25		—		25		50
Total	$	523	$	95	$	480	$	4,130	$	5,228	$	5,214	$	153	$	40	$	193	$	365

(a) No credit arrangements expire in 2017.

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 three months of 2014:

Company(a)	Other Long-Term Debt Issuances		Other Long-Term Debt Redemptions(b)
	(in millions)
Georgia Power	$	1,000	$	1
Mississippi Power	250		1
Southern Power	1		1
Other	—		6
Total	$	1,251	$	9

(a) Southern Company, Alabama Power, and Gulf Power did not issue or redeem any long-term debt during the first three months of 2014.

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

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 will 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.

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.

Southern Power

In March 2014, Southern Power issued an additional $0.6 million under a promissory note, due April 30, 2033, to Turner Renewable Energy, LLC (TRE) related to the financing of Campo Verde Solar, LLC.

In March 2014, Southern Power prepaid $0.8 million of long-term debt to TRE.

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Retirement Benefits

3 Months Ended

Mar. 31, 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 months ended March 31, 2014 and 2013 were as follows:

Pension Plans	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power
	(in millions)
Three Months Ended March 31, 2014
Service cost	$	53		$	12		$	16		$	3		$	3
Interest cost	109			26			38			5			5
Expected return on plan assets	(161		)	(42		)	(57		)	(7		)	(7		)
Amortization:
Prior service costs	6			1			3			—			—
Net (gain)/loss	28			8			10			1			1
Net cost	$	35		$	5		$	10		$	2		$	2
Three Months Ended March 31, 2013
Service cost	$	58		$	13		$	17		$	3		$	3
Interest cost	97			23			34			4			5
Expected return on plan assets	(151		)	(39		)	(53		)	(6		)	(7		)
Amortization:
Prior service costs	7			2			3			—			—
Net (gain)/loss	50			13			19			2			2
Net cost	$	61		$	12		$	20		$	3		$	3

Postretirement Benefits	Southern Company			Alabama Power			Georgia Power			Gulf Power		Mississippi Power
	(in millions)
Three Months Ended March 31, 2014
Service cost	$	5		$	1		$	2		$	—	$	—
Interest cost	20			5			8			1		1
Expected return on plan assets	(15		)	(6		)	(6		)	—		—
Amortization:
Prior service costs	1			1			—			—		—
Net (gain)/loss	1			—			—			—		—
Net cost	$	12		$	1		$	4		$	1	$	1
Three Months Ended March 31, 2013
Service cost	$	6		$	2		$	2		$	—	$	—
Interest cost	19			5			8			1		1
Expected return on plan assets	(14		)	(6		)	(6		)	—		—
Amortization:
Transition obligation	1			—			1			—		—
Prior service costs	1			1			—			—		—
Net (gain)/loss	3			—			2			—		—
Net cost	$	16		$	2		$	7		$	1	$	1

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Derivatives

3 Months Ended

Mar. 31, 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 uncontracted generating capacity. Further, the traditional operating companies may be 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.

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

Energy-related derivative contracts are accounted for under one of three methods:

• Regulatory Hedges — Energy-related derivative contracts which are designated as regulatory hedges relate primarily to the traditional operating companies' fuel-hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through the respective fuel cost recovery clauses.

• Cash Flow Hedges — Gains and losses on energy-related derivatives designated as cash flow hedges which are mainly used to hedge anticipated purchases and sales and are initially deferred in OCI before being recognized in the statements of income in the same period as the hedged transactions are reflected in earnings.

• Not Designated — Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.

Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric industry. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered.

At March 31, 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	256	2018	2017
Alabama Power	65	2017	—
Georgia Power	53	2017	—
Gulf Power	83	2018	—
Mississippi Power	54	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 7 million mmBtu for Southern Company, 1 million mmBtu for Alabama Power, 4 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 revenue and fuel expense for the next 12-month period ending March 31, 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 March 31, 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) March 31, 2014
	(in millions)					(in millions)
Fair value hedges of existing debt
Southern Company	$	350	4.15%	3-month LIBOR  + 1.96%	May 2014	$	3

The estimated pre-tax gains (losses) that will be reclassified from accumulated OCI to interest expense for the next 12-month period ending March 31, 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 a cash flow hedge 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.

During the quarter ended March 31, 2014, Mississippi Power's fair value hedge was de-designated and the related ineffectiveness was recorded as a regulatory asset and was immaterial. At March 31, 2014, the fair value of the foreign currency derivatives outstanding was immaterial.

Derivative Financial Statement Presentation and Amounts

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

Asset Derivatives at March 31, 2014
	Fair Value
Derivative Category and Balance Sheet Location	Southern Company		Alabama Power		Georgia Power		Gulf Power		Mississippi Power		Southern Power
	(in millions)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets	$	36	$	11	$	8	$	10	$	7
Other deferred charges and assets	4		1		—		2		1
Total derivatives designated as hedging instruments for regulatory purposes	$	40	$	12	$	8	$	12	$	8	N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current assets	3		—		—		—		—		$	—
Total asset derivatives	$	43	$	12	$	8	$	12	$	8	$	—

Liability Derivatives at March 31, 2014
	Fair Value
Derivative Category and Balance Sheet Location	Southern Company		Alabama Power		Georgia Power		Gulf Power		Mississippi Power		Southern Power
	(in millions)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Liabilities from risk management activities	$	17	$	1	$	10	$	4	$	2
Other deferred credits and liabilities	26		5		6		9		6
Total liability derivatives	$	43	$	6	$	16	$	13	$	8	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 March 31, 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 March 31, 2014
	Fair Value
	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power			Southern Power
	(in millions)
Assets
Energy-related derivatives:
Energy-related derivatives presented in the Balance Sheet (a)	$	40		$	12		$	8		$	12		$	8		$	—
Gross amounts not offset in the Balance Sheet (b)	(33		)	(6		)	(8		)	(8		)	(5		)	—
Net energy-related derivative assets	$	7		$	6		$	—		$	4		$	3		$	—
Liabilities
Energy-related derivatives:
Energy-related derivatives presented in the Balance Sheet (a)	$	(43	)	$	(6	)	$	(16	)	$	(13	)	$	(8	)	$	—
Gross amounts not offset in the Balance Sheet (b)	33			6			8			8			5			—
Net energy-related derivative liabilities	$	(10	)	$	—		$	(8	)	$	(5	)	$	(3	)	$	—

(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 March 31, 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 March 31, 2014
Derivative Category and Balance Sheet Location	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power
	(in millions)
Energy-related derivatives:
Other regulatory assets, current	$	(17	)	$	(1	)	$	(10	)	$	(4	)	$	(2	)
Other regulatory assets, deferred	(26		)	(5		)	(6		)	(9		)	(6		)
Other regulatory liabilities, current	36			11			8			10			7
Other regulatory liabilities, deferred	4			1			—			2			1
Total energy-related derivative gains (losses)	$	(3	)	$	6		$	(8	)	$	(1	)	$	—

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 months ended March 31, 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 months ended March 31, 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 months ended March 31, 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 substantial 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 months ended March 31, 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 March 31, 2014, the fair value of derivative liabilities with contingent features was immaterial for all registrants.

At March 31, 2014, the registrants' collateral posted with their derivative counterparties was immaterial. The maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, were $2 million and include certain agreements that could require collateral in the event that one or more Southern Company power pool participants has a credit rating change to below investment grade.

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

Southern Company, the traditional operating companies, and Southern Power are exposed to losses related to financial instruments in the event of counterparties' nonperformance. Southern Company, the traditional operating companies, and Southern Power only enter into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's and S&P or with counterparties who have posted collateral to cover potential credit exposure. Southern Company, the traditional operating companies, and Southern Power have also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate Southern Company's, the traditional operating companies', and Southern Power's exposure to counterparty credit risk. Therefore, Southern Company, the traditional operating companies, and Southern Power do not anticipate a material adverse effect on the financial statements as a result of counterparty nonperformance.

XML

Fair Value Measurements - Assets and Liabilities Measured at Fair Value on a Recurring Basis (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014
Fair Value, Measurements, Recurring [Member]
Assets:
Energy-related derivatives	$ 40
Interest rate derivatives	3
Nuclear decommissioning trusts	1,512	[1]
Cash equivalents	408
Other	13
Fair value assets, total	1,976
Liabilities:
Energy-related derivatives	43
Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member]
Assets:
Energy-related derivatives	0
Interest rate derivatives	3
Nuclear decommissioning trusts	626	[1]
Cash equivalents	408
Other	9
Fair value assets, total	1,046
Liabilities:
Energy-related derivatives	0
Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member]
Assets:
Energy-related derivatives	40
Interest rate derivatives	0
Nuclear decommissioning trusts	884	[1]
Cash equivalents	0
Other	0
Fair value assets, total	924
Liabilities:
Energy-related derivatives	43
Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member]
Assets:
Energy-related derivatives	0
Interest rate 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	12
Fair value assets, total	914
Liabilities:
Energy-related derivatives	6
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Domestic Equity [Member]
Assets:
Nuclear decommissioning trusts	480	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Foreign Equity [Member]
Assets:
Nuclear decommissioning trusts	100	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | U.S. Treasury and government agency securities [Member]
Assets:
Nuclear decommissioning trusts	29	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Corporate bonds [Member]
Assets:
Nuclear decommissioning trusts	88	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Mortgage and asset backed securities [Member]
Assets:
Nuclear decommissioning trusts	18	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Other investments [Member]
Assets:
Nuclear decommissioning trusts	11	[2]
Cash equivalents	176
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	614
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	403	[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	35	[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	12
Fair value assets, total	298
Liabilities:
Energy-related derivatives	6
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Domestic Equity [Member]
Assets:
Nuclear decommissioning trusts	77	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Foreign Equity [Member]
Assets:
Nuclear decommissioning trusts	65	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | U.S. Treasury and government agency securities [Member]
Assets:
Nuclear decommissioning trusts	29	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Corporate bonds [Member]
Assets:
Nuclear decommissioning trusts	88	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Mortgage and asset backed securities [Member]
Assets:
Nuclear decommissioning trusts	18	[2]
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other investments [Member]
Assets:
Nuclear decommissioning trusts	9	[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]
Cash equivalents	0
Georgia Power [Member]
Assets:
Nuclear decommissioning trusts	51
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member]
Assets:
Energy-related derivatives	8
Fair value assets, total	794
Liabilities:
Energy-related derivatives	16
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Domestic Equity [Member]
Assets:
Nuclear decommissioning trusts	189	[2],[3]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Foreign Equity [Member]
Assets:
Nuclear decommissioning trusts	131	[2],[3]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | U.S. Treasury and government agency securities [Member]
Assets:
Nuclear decommissioning trusts	125	[2],[3]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Municipal bonds [Member]
Assets:
Nuclear decommissioning trusts	40	[2],[3]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Corporate bonds [Member]
Assets:
Nuclear decommissioning trusts	153	[2],[3]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Mortgage and asset backed securities [Member]
Assets:
Nuclear decommissioning trusts	103	[2],[3]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Other investments [Member]
Assets:
Nuclear decommissioning trusts	45	[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	188
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	188	[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	0	[2],[3]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member]
Assets:
Energy-related derivatives	8
Fair value assets, total	606
Liabilities:
Energy-related derivatives	16
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	131	[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	125	[2],[3]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Municipal bonds [Member]
Assets:
Nuclear decommissioning trusts	40	[2],[3]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Corporate bonds [Member]
Assets:
Nuclear decommissioning trusts	153	[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	103	[2],[3]
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other investments [Member]
Assets:
Nuclear decommissioning trusts	45	[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	13
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	13
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	8
Cash equivalents	63
Fair value assets, total	71
Liabilities:
Energy-related derivatives	8
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	63
Fair value assets, total	63
Liabilities:
Energy-related derivatives	0
Mississippi Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member]
Assets:
Energy-related derivatives	8
Cash equivalents	0
Fair value assets, total	8
Liabilities:
Energy-related derivatives	8
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	115
Southern Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member]
Assets:
Cash equivalents	115
Southern Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member]
Assets:
Cash equivalents	0
Southern Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member]
Assets:
Cash equivalents	$ 0

[1] For additional detail, see the nuclear decommissioning trusts sections for Alabama Power and Georgia Power in this table.

[2] Excludes receivables related to investment income, pending investment sales, 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 March 31, 2014, approximately $51 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.

XML

Segment and Related Information - Financial Data for Products and Services (Details) (USD $)	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Revenue from External Customer [Line Items]
Electric Revenue	$ 4,627,000,000	$ 3,885,000,000
Financial data for Products and Services
Electric Utilities' Revenues	4,644,000,000	3,897,000,000
Retail [Member]
Revenue from External Customer [Line Items]
Electric Revenue	3,858,000,000	3,298,000,000
Wholesale [Member]
Revenue from External Customer [Line Items]
Electric Revenue	604,000,000	432,000,000
Other [Member]
Revenue from External Customer [Line Items]
Electric Revenue	$ 165,000,000	$ 155,000,000

XML

Stockholders' Equity (Policies)

3 Months Ended

Mar. 31, 2014

Equity [Abstract]

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.

XML

Financing (Tables)

3 Months Ended

Mar. 31, 2014

Debt Disclosure [Abstract]

Credit arrangements by company

The following table outlines the committed credit arrangements by company as of March 31, 2014:

	Expires(a)												Executable Term Loans				Due Within One Year
Company	2014		2015		2016		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	238		35		—		1,030		1,303		1,303		53		—		53		185
Georgia Power	—		—		150		1,600		1,750		1,736		—		—		—		—
Gulf Power	75		35		165		—		275		275		50		—		50		60
Mississippi Power	135		—		165		—		300		300		25		40		65		70
Southern Power	—		—		—		500		500		500		—		—		—		—
Other	75		25		—		—		100		100		25		—		25		50
Total	$	523	$	95	$	480	$	4,130	$	5,228	$	5,214	$	153	$	40	$	193	$	365

(a) No credit arrangements expire in 2017.

Schedule of Long-term Debt Financing Activities

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

Company(a)	Other Long-Term Debt Issuances		Other Long-Term Debt Redemptions(b)
	(in millions)
Georgia Power	$	1,000	$	1
Mississippi Power	250		1
Southern Power	1		1
Other	—		6
Total	$	1,251	$	9

(a) Southern Company, Alabama Power, and Gulf Power did not issue or redeem any long-term debt during the first three months of 2014.

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

XML

Acquisitions (Details) (USD $)					3 Months Ended
	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2014 Southern Power [Member]	Dec. 31, 2013 Southern Power [Member]	Mar. 31, 2014 Adobe Solar LLC [Member] Southern Power [Member] MW
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					$ 94,400,000
Business Acquisition Cost Paid At Closing					75,500,000
Construction in Progress, Gross	$ 7,425,000,000	$ 7,151,000,000	$ 10,926,000	$ 9,843,000	$ 81,000,000

XML

Financing Debt Instruments (Details) (USD $)	3 Months Ended						0 Months Ended						1 Months Ended	3 Months Ended					1 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Mar. 31, 2014 Debt Redemptions [Member]		Mar. 31, 2014 Debt Issuances [Member]	Mar. 31, 2014 Traditional Operating Companies [Member]	Feb. 20, 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]	Mar. 31, 2014 Georgia Power [Member] Debt Redemptions [Member]		Mar. 31, 2014 Georgia Power [Member] Debt Issuances [Member]	Jan. 31, 2014 Mississippi Power [Member]	Mar. 31, 2014 Mississippi Power [Member]	Mar. 31, 2013 Mississippi Power [Member]	Mar. 31, 2014 Mississippi Power [Member] Debt Redemptions [Member]		Mar. 31, 2014 Mississippi Power [Member] Debt Issuances [Member]	Mar. 31, 2014 Southern Power [Member]	Mar. 31, 2014 Southern Power [Member] Debt Redemptions [Member]		Mar. 31, 2014 Southern Power [Member] Debt Issuances [Member]	Mar. 31, 2014 Other Subsidiaries [Member] Debt Redemptions [Member]		Mar. 31, 2014 Other Subsidiaries [Member] Debt Issuances [Member]	Mar. 31, 2014 Plant Vogtle Units 3 And 4 [Member] Georgia Power [Member]
Debt Instrument [Line Items]
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	1,800,000,000					559,000,000
Debt Instrument, Face Amount								500,000,000	500,000,000
Other Long-term Debt			9,000,000	[1]	1,251,000,000					1,000,000	[1]	1,000,000,000				1,000,000	[1]	250,000,000		1,000,000	[1]	1,000,000	6,000,000	[1]	0
Debt Instrument, Interest Rate, Stated Percentage								3.86%	3.488%
Payments of Debt Issuance Costs							66,000,000
Bank Loans Period Of Extension													18 months
Aggregate Principal Amount Of Floating Rate Bank Loan													250,000,000
Debt Instrument, Description of Variable Rate Basis														P1M
Promissory Note																			600,000
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.

XML

Condensed Consolidated Statements of Cash Flows (Unaudited) (USD $)	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Operating Activities:
Consolidated net income	$ 368,000,000	$ 97,000,000
Adjustments to reconcile consolidated net income to net cash provided from operating activities --
Depreciation and amortization, total	587,000,000	568,000,000
Deferred income taxes	(37,000,000)	(92,000,000)
Allowance for equity funds used during construction	(57,000,000)	(41,000,000)
Stock based compensation expense	28,000,000	26,000,000
Estimated loss on Kemper IGCC	380,000,000	540,000,000
Other, net	(8,000,000)	(19,000,000)
Changes in certain current assets and liabilities --
-Receivables	(128,000,000)	29,000,000
-Fossil fuel stock	441,000,000	36,000,000
-Materials and supplies	(5,000,000)	52,000,000
-Other current assets	(114,000,000)	(72,000,000)
-Accounts payable	(109,000,000)	(47,000,000)
-Accrued taxes	(44,000,000)	(98,000,000)
-Accrued compensation	(144,000,000)	(282,000,000)
-Other current liabilities	(55,000,000)	40,000,000
Net cash provided from operating activities	1,103,000,000	737,000,000
Investing Activities:
Property additions	(1,180,000,000)	(1,197,000,000)
Investment of restricted cash	0	(78,000,000)
Distribution of restricted cash	9,000,000	1,000,000
Nuclear decommissioning trust fund purchases	(231,000,000)	(262,000,000)
Nuclear decommissioning trust fund sales	229,000,000	261,000,000
Cost of removal, net of salvage	(22,000,000)	(30,000,000)
Change in construction payables	51,000,000	6,000,000
Prepaid long-term service agreement	(64,000,000)	(31,000,000)
Other investing activities	(7,000,000)	51,000,000
Net cash used for investing activities	(1,215,000,000)	(1,279,000,000)
Financing Activities:
Increase (decrease) in notes payable, net	(884,000,000)	468,000,000
Proceeds --
Long-term debt issuances	1,251,000,000	1,035,000,000
Interest-bearing refundable deposit related to asset sale	75,000,000	0
Common stock issuances	128,000,000	42,000,000
Redemptions --
Long-term debt	(9,000,000)	(656,000,000)
Common stock repurchased	(4,000,000)	(18,000,000)
Payment of common stock dividends	(451,000,000)	(426,000,000)
Payment of dividends on preferred and preference stock of subsidiaries	(17,000,000)	(16,000,000)
Other financing activities	(46,000,000)	0
Net cash provided from (used for) financing activities	43,000,000	429,000,000
Net Change in Cash and Cash Equivalents	(69,000,000)	(113,000,000)
Cash and Cash Equivalents at Beginning of Period	659,000,000	628,000,000
Cash and Cash Equivalents at End of Period	590,000,000	515,000,000
Cash paid (received) during the period for --
Interest (net of capitalized amounts)	186,000,000	187,000,000
Income taxes, net	(7,000,000)	4,000,000
Noncash transactions - accrued property additions at end of period	450,000,000	501,000,000
Alabama Power [Member]
Operating Activities:
Consolidated net income	197,000,000	151,000,000
Adjustments to reconcile consolidated net income to net cash provided from operating activities --
Depreciation and amortization, total	210,000,000	206,000,000
Deferred income taxes	25,000,000	25,000,000
Allowance for equity funds used during construction	(10,000,000)	(8,000,000)
Other, net	(22,000,000)	9,000,000
Changes in certain current assets and liabilities --
-Receivables	(17,000,000)	(13,000,000)
-Fossil fuel stock	99,000,000	28,000,000
-Materials and supplies	3,000,000	16,000,000
-Other current assets	(81,000,000)	(71,000,000)
-Accounts payable	(139,000,000)	(124,000,000)
-Accrued taxes	147,000,000	90,000,000
-Accrued compensation	(37,000,000)	(61,000,000)
-Retail fuel cost over recovery - short-term	(20,000,000)	21,000,000
-Other current liabilities	(3,000,000)	1,000,000
Net cash provided from operating activities	352,000,000	270,000,000
Investing Activities:
Property additions	(287,000,000)	(274,000,000)
Nuclear decommissioning trust fund purchases	(56,000,000)	(57,000,000)
Nuclear decommissioning trust fund sales	56,000,000	57,000,000
Cost of removal, net of salvage	(12,000,000)	(9,000,000)
Change in construction payables	49,000,000	(1,000,000)
Other investing activities	(5,000,000)	37,000,000
Net cash used for investing activities	(255,000,000)	(247,000,000)
Financing Activities:
Increase (decrease) in notes payable, net	0	45,000,000
Proceeds --
Capital contributions from parent company	7,000,000	5,000,000
Redemptions --
Payment of preferred and preference stock dividends	(10,000,000)	(10,000,000)
Payment of common stock dividends	(137,000,000)	(132,000,000)
Other financing activities	0	(3,000,000)
Net cash provided from (used for) financing activities	(140,000,000)	(95,000,000)
Net Change in Cash and Cash Equivalents	(43,000,000)	(72,000,000)
Cash and Cash Equivalents at Beginning of Period	295,000,000	137,000,000
Cash and Cash Equivalents at End of Period	252,000,000	65,000,000
Cash paid (received) during the period for --
Interest (net of capitalized amounts)	61,000,000	64,000,000
Income taxes, net	(28,000,000)	(3,000,000)
Noncash transactions - accrued property additions at end of period	66,000,000	30,000,000
Georgia Power [Member]
Operating Activities:
Consolidated net income	270,000,000	201,000,000
Adjustments to reconcile consolidated net income to net cash provided from operating activities --
Depreciation and amortization, total	250,000,000	239,000,000
Deferred income taxes	96,000,000	59,000,000
Allowance for equity funds used during construction	(6,000,000)	(6,000,000)
Retail fuel cost over recovery - long-term	(44,000,000)	(58,000,000)
Deferred expenses	33,000,000	31,000,000
Other, net	(14,000,000)	(27,000,000)
Changes in certain current assets and liabilities --
-Receivables	(83,000,000)	40,000,000
-Fossil fuel stock	257,000,000	(4,000,000)
-Prepaid income taxes	(11,000,000)	11,000,000
-Other current assets	(12,000,000)	42,000,000
-Accounts payable	(28,000,000)	78,000,000
-Accrued taxes	(166,000,000)	(127,000,000)
-Accrued compensation	(38,000,000)	(66,000,000)
-Retail fuel cost over recovery - short-term	(14,000,000)	10,000,000
-Other current liabilities	9,000,000	5,000,000
Net cash provided from operating activities	499,000,000	428,000,000
Investing Activities:
Property additions	(460,000,000)	(419,000,000)
Investment of restricted cash	0	(18,000,000)
Nuclear decommissioning trust fund purchases	(175,000,000)	(205,000,000)
Nuclear decommissioning trust fund sales	173,000,000	204,000,000
Cost of removal, net of salvage	(3,000,000)	(17,000,000)
Prepaid long-term service agreement	(44,000,000)	(5,000,000)
Change in construction payables, net of joint owner portion	28,000,000	(25,000,000)
Other investing activities	1,000,000	6,000,000
Net cash used for investing activities	(480,000,000)	(479,000,000)
Financing Activities:
Increase (decrease) in notes payable, net	(749,000,000)	300,000,000
Proceeds --
Capital contributions from parent company	12,000,000	11,000,000
Pollution control revenue bonds issuances	0	18,000,000
Senior notes issuances	0	650,000,000
FFB loan	1,000,000,000	0
Redemptions --
Senior notes	0	(650,000,000)
Payment of preferred and preference stock dividends	(4,000,000)	(4,000,000)
Payment of common stock dividends	(238,000,000)	(227,000,000)
FFB loan issuance costs	(49,000,000)	(1,000,000)
Other financing activities	(3,000,000)	(12,000,000)
Net cash provided from (used for) financing activities	(31,000,000)	85,000,000
Net Change in Cash and Cash Equivalents	(12,000,000)	34,000,000
Cash and Cash Equivalents at Beginning of Period	30,000,000	45,000,000
Cash and Cash Equivalents at End of Period	18,000,000	79,000,000
Cash paid (received) during the period for --
Interest (net of capitalized amounts)	71,000,000	72,000,000
Income taxes, net	11,000,000	3,000,000
Noncash transactions - accrued property additions at end of period	229,000,000	212,000,000
Gulf Power [Member]
Operating Activities:
Consolidated net income	38,994,000	23,343,000
Adjustments to reconcile consolidated net income to net cash provided from operating activities --
Depreciation and amortization, total	33,764,000	38,794,000
Deferred income taxes	14,287,000	16,777,000
Allowance for equity funds used during construction	(2,379,000)	(1,134,000)
Pension, postretirement, and other employee benefits	1,553,000	2,889,000
Stock based compensation expense	734,000	669,000
Other, net	503,000	2,485,000
Changes in certain current assets and liabilities --
-Receivables	(25,275,000)	(2,305,000)
-Prepayments	1,126,000	934,000
-Fossil fuel stock	46,267,000	1,423,000
-Materials and supplies	(167,000)	(513,000)
-Prepaid income taxes	10,495,000	(7,667,000)
-Other current assets	(422,000)	0
-Accounts payable	5,746,000	(17,812,000)
-Accrued taxes	9,110,000	5,380,000
-Accrued compensation	(4,801,000)	(9,451,000)
-Over recovered regulatory clause revenues	5,490,000	(10,186,000)
-Other current liabilities	7,125,000	6,073,000
Net cash provided from operating activities	142,150,000	49,699,000
Investing Activities:
Property additions	(78,789,000)	(66,696,000)
Cost of removal, net of salvage	(3,059,000)	(3,469,000)
Change in construction payables	1,129,000	1,787,000
Payments pursuant to long-term service agreements	(2,127,000)	(1,558,000)
Other investing activities	97,000	243,000
Net cash used for investing activities	(82,749,000)	(69,693,000)
Financing Activities:
Increase (decrease) in notes payable, net	(75,388,000)	5,809,000
Proceeds --
Capital contributions from parent company	668,000	556,000
Common stock issuances	50,000,000	40,000,000
Redemptions --
Payment of preferred and preference stock dividends	(2,251,000)	(1,551,000)
Payment of common stock dividends	(30,800,000)	(28,850,000)
Other financing activities	(27,000)	(206,000)
Net cash provided from (used for) financing activities	(57,798,000)	15,758,000
Net Change in Cash and Cash Equivalents	1,603,000	(4,236,000)
Cash and Cash Equivalents at Beginning of Period	21,753,000	32,167,000
Cash and Cash Equivalents at End of Period	23,356,000	27,931,000
Cash paid (received) during the period for --
Interest (net of capitalized amounts)	4,630,000	8,306,000
Income taxes, net	(5,839,000)	3,886,000
Noncash transactions - accrued property additions at end of period	33,186,000	22,462,000
Mississippi Power [Member]
Operating Activities:
Consolidated net income	(171,615,000)	(245,888,000)
Adjustments to reconcile consolidated net income to net cash provided from operating activities --
Depreciation and amortization, total	24,035,000	21,692,000
Deferred income taxes	(124,158,000)	(174,082,000)
Investment tax credits	2,626,000	0
Allowance for equity funds used during construction	(38,082,000)	(26,074,000)
Pension, postretirement, and other employee benefits	1,037,000	2,926,000
Stock based compensation expense	1,324,000	1,033,000
Regulatory assets associated with Kemper IGCC	(13,226,000)	(6,843,000)
Estimated loss on Kemper IGCC	380,000,000	462,000,000
Kemper regulatory deferral	34,342,000	0
Other, net	2,555,000	(628,000)
Changes in certain current assets and liabilities --
-Receivables	(13,525,000)	(5,226,000)
-Fossil fuel stock	36,595,000	8,415,000
-Materials and supplies	(2,970,000)	(4,744,000)
-Prepaid income taxes	(32,720,000)	1,573,000
-Other current assets	(2,000,000)	(2,389,000)
-Accounts payable	14,900,000	(13,783,000)
-Accrued taxes	(54,996,000)	(45,429,000)
-Accrued interest	8,225,000	6,570,000
-Accrued compensation	(2,080,000)	(10,247,000)
-Over recovered regulatory clause revenues	(18,358,000)	2,996,000
-Other current liabilities	293,000	2,971,000
Net cash provided from operating activities	32,202,000	(25,157,000)
Investing Activities:
Property additions	(323,816,000)	(369,313,000)
Cost of removal, net of salvage	(3,997,000)	(902,000)
Change in construction payables	(30,519,000)	23,150,000
Capital grant proceeds	0	1,784,000
Other investing activities	(3,100,000)	(7,145,000)
Net cash used for investing activities	(361,432,000)	(352,426,000)
Proceeds --
Capital contributions from parent company	687,000	100,552,000
Bonds-Other	0	15,814,000
Interest-bearing refundable deposit related to asset sale	75,000,000	0
Other long-term debt issuances	250,000,000	350,000,000
Redemptions — Capital leases	(623,000)	0
Redemptions --
Payment of preferred and preference stock dividends	(433,000)	(433,000)
Payment of common stock dividends	0	(44,190,000)
Return of capital	(54,930,000)	0
Other financing activities	(454,000)	(1,409,000)
Net cash provided from (used for) financing activities	269,247,000	420,334,000
Net Change in Cash and Cash Equivalents	(59,983,000)	42,751,000
Cash and Cash Equivalents at Beginning of Period	145,165,000	145,008,000
Cash and Cash Equivalents at End of Period	85,182,000	187,759,000
Cash paid (received) during the period for --
Interest (net of capitalized amounts)	3,028,000	4,860,000
Income taxes, net	26,078,000	(25,000)
Noncash transactions - accrued property additions at end of period	132,065,000	238,013,000
Southern Power [Member]
Operating Activities:
Consolidated net income	34,287,000	29,192,000
Adjustments to reconcile consolidated net income to net cash provided from operating activities --
Depreciation and amortization, total	50,264,000	42,790,000
Deferred income taxes	(14,087,000)	13,587,000
Investment tax credits	26,134,000	(493,000)
Deferred revenues	(20,033,000)	(20,432,000)
Other, net	2,184,000	233,000
Changes in certain current assets and liabilities --
-Receivables	21,034,000	11,743,000
-Fossil fuel stock	2,487,000	1,840,000
-Materials and supplies	(2,763,000)	(1,546,000)
-Prepaid income taxes	14,911,000	1,600,000
-Other current assets	2,129,000	1,324,000
-Accounts payable	2,232,000	(6,933,000)
-Accrued taxes	5,831,000	4,155,000
-Accrued interest	(14,502,000)	(10,841,000)
-Other current liabilities	(42,000)	(314,000)
Net cash provided from operating activities	110,066,000	65,905,000
Investing Activities:
Property additions	(5,468,000)	(58,553,000)
Change in construction payables	543,000	3,704,000
Payments pursuant to long-term service agreements	(10,029,000)	(11,741,000)
Other investing activities	54,000	(224,000)
Net cash used for investing activities	(14,900,000)	(66,814,000)
Financing Activities:
Increase (decrease) in notes payable, net	0	76,985,000
Proceeds --
Capital contributions from parent company	(2,752,000)	1,033,000
Other long-term debt issuances	639,000	1,717,000
Redemptions --
Other long-term debt	(818,000)	(220,000)
Distributions to noncontrolling interest	(150,000)	0
Contributions from noncontrolling interest	471,000	0
Payment of common stock dividends	(32,780,000)	(32,280,000)
Other financing activities	631,000	678,000
Net cash provided from (used for) financing activities	(34,759,000)	47,913,000
Net Change in Cash and Cash Equivalents	60,407,000	47,004,000
Cash and Cash Equivalents at Beginning of Period	68,744,000	28,592,000
Cash and Cash Equivalents at End of Period	129,151,000	75,596,000
Cash paid (received) during the period for --
Interest (net of capitalized amounts)	35,790,000	28,120,000
Income taxes, net	(44,468,000)	(179,000)
Noncash transactions - accrued property additions at end of period	$ 4,810,000	$ 8,907,000

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Contingencies and Regulatory Matters

3 Months Ended

Mar. 31, 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 March 31, 2014 was $18 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 March 31, 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, the Texas Commission on Environmental Quality (TCEQ) designated Mississippi Power as a PRP at a site in Texas. The site was owned by an electric transformer company that handled Mississippi Power's transformers as well as those of many other entities. 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. The remediation expenses incurred by Mississippi Power are expected to be recovered through the ECO Plan and are not expected to have a material impact on Southern Company's or Mississippi Power's financial statements.

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. No amounts have been recognized in the financial statements as of March 31, 2014 for any potential recoveries from these lawsuits. The final outcome of these matters cannot be determined at this time; however, no material impact on Southern Company's, Alabama Power's, or Georgia Power's net income is expected.

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 Mississippi Power's settlement agreement with its wholesale customers for revised rates related to the wholesale Municipal and Rural Associations (MRA) cost-based electric tariff. 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 additional increase in the MRA cost-based electric tariff. The settlement agreement, if approved by the FERC, 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. If the settlement agreement is approved by the FERC, the amount of base rate revenues to be received in 2014 from the agreed upon increase is expected to be approximately $6.9 million. The ultimate outcome of this matter cannot be determined at this time.

Retail Regulatory Matters

Alabama Power

See Note 3 to the financial statements of Southern Company and Alabama Power under "Retail Regulatory Matters – Alabama Power" and "Retail Regulatory Matters," respectively, in Item 8 of the Form 10-K for additional information regarding Alabama Power's recovery of retail costs through various regulatory clauses and accounting orders. The recovery balance of each regulatory clause follows:

Regulatory Clause	Balance Sheet Line Item	March 31, 2014		December 31, 2013
		(in millions)
Rate CNP Environmental – Under	Deferred under recovered regulatory clause revenues	$	13	$	7
Rate CNP PPA – Under	Deferred under recovered regulatory clause revenues	23		18
Retail Energy Cost Recovery – Over	Other regulatory liabilities, current	22		27
	Deferred over recovered regulatory clause revenues	—		15
Natural Disaster Reserve	Other regulatory liabilities, deferred	91		96

Georgia Power

Fuel Cost Recovery

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

As of March 31, 2014, Georgia Power's under recovered fuel balance totaled $157 million and is included in current assets and other deferred charges and assets on Southern Company's and Georgia Power's Condensed Balance Sheets herein. As of December 31, 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 in the financial statements are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, any 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

Georgia Power defers and recovers certain costs related to damages from major storms as mandated by the Georgia PSC. As of March 31, 2014 and December 31, 2013, the balance in the regulatory asset related to storm damage was $110 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 an 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 March 31, 2014, approximately $32 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 commercial operation date 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 expects to resume filing semi-annual VCM reports in 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. The portion of additional costs claimed by the Contractor 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. 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. 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. While litigation has commenced 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 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 ROE range then in effect. In the first quarter 2014, Gulf Power recognized a reduction in depreciation expense of $6.2 million.

Cost Recovery Clauses

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

Recovery Clause	Balance Sheet Location	March 31, 2014		December 31, 2013
		(in millions)
Fuel Cost Recovery – Under	Under recovered regulatory clause revenues	$	35.7	$	21.0
Purchased Power Capacity Recovery – Over	Other regulatory liabilities, current	5.5		—
Purchased Power Capacity Recovery – Under	Under recovered regulatory clause revenues	—		2.8
Environmental Cost Recovery – Under	Under recovered regulatory clause revenues	17.1		14.4
Energy Conservation Cost Recovery – Under	Under recovered regulatory clause revenues	6.3		7.0

Mississippi Power

Performance Evaluation Plan

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

On March 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.

The ultimate outcome of this matter 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. Also in 2012, the Sierra Club filed a notice of appeal of the order with the Chancery Court. 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 March 31, 2014, total project expenditures were $370.2 million, of which Mississippi Power's portion was $188.1 million, excluding AFUDC of $10.7 million.

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

Fuel Cost Recovery

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

At March 31, 2014, the amount of under recovered retail fuel costs included on Mississippi Power's Condensed Balance Sheet herein was $1.8 million compared to over recovered retail fuel costs of $14.5 million at December 31, 2013.

Ad Valorem Tax Adjustment

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, 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. The ultimate outcome of the CPCN challenge 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 Settlement Agreement (described 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. However, as a result of the construction issues identified in March 2014, as well as the risk of additional factors that have the potential to further extend construction and start-up as described below, the in-service date for the remainder of the Kemper IGCC, including the gasification system, is currently expected to occur in the first half of 2015.

Mississippi Power's 2010 project estimate, current cost estimate, and actual costs incurred as of March 31, 2014 for the Kemper IGCC are as follows:

Cost Category	2010 Project Estimate(e)		Current Estimate		Actual Costs at March 31, 2014
	(in billions)
Plant Subject to Cost Cap(a)	$	2.40	$	4.44	$	3.52
Lignite Mine and Equipment	0.21		0.23		0.23
CO2 Pipeline Facilities	0.14		0.11		0.10
AFUDC(b)(c)	0.17		0.55		0.32
General Exceptions	0.05		0.10		0.07
Regulatory Asset(c)(d)	—		0.10		0.08
Total Kemper IGCC(a)(c)	$	2.97	$	5.53	$	4.32

(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 March 31, 2014, $2.67 billion was included in CWIP (which is net of the DOE Grants and estimated probable losses of $1.56 billion), $83.9 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. These amounts are 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 estimated to result in additional costs of approximately $25 million per month.

Any further cost increases and/or extensions of the in-service date with respect to the Kemper IGCC may result from factors including, but not limited to, labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under construction or other agreements, operational performance, and/or start-up activities for this "first-of-a-kind" technology, including major equipment failure, system integration, and operations, and/or unforeseen engineering problems. 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 and/or any amount in excess of the $1.0 billion securitization limit (described below) 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.

Settlement Agreement

In January 2013, Mississippi Power entered into the 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. Under the 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 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 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 Settlement Agreement provides that Mississippi Power may terminate the 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 Settlement Agreement, or if the Mississippi PSC fails to comply with the requirements of the Settlement Agreement. Mississippi Power continues to work with the Mississippi PSC and the Mississippi Public Utilities Staff to implement the requirements of the Settlement Agreement.

2013 MPSC Rate Order

Consistent with the terms of the 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, to be recorded to a regulatory liability to be used to mitigate rate impacts when the Kemper IGCC is placed in service.

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. Amounts collected through these rates are being recorded as a regulatory liability to be used to mitigate customer rate impacts after the Kemper IGCC is placed in service. As of March 31, 2014, $135.5 million had been collected, with $4.4 million recognized in retail rate revenues in the first quarter 2014 in Southern Company's and Mississippi Power's Condensed Statements of Income herein and the remainder deferred in other regulatory liabilities 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 $120 million to $150 million. See "Investment Tax Credits and Bonus Depreciation" herein for additional information regarding bonus depreciation.

In 2014, 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 approximately $45 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 prudence review of Kemper IGCC costs incurred through March 31, 2013, as provided for in the Settlement Agreement, is ongoing, with hearings currently expected to occur in the third quarter 2014. A final review of all costs incurred after March 31, 2013 is expected to be completed within six months of the Kemper IGCC's in-service date. Furthermore, regardless of any prudence determinations made during the construction and start-up period, the Mississippi PSC has the right to make a final prudence determination after the Kemper IGCC has been placed in service. The Mississippi PSC through its scheduling orders 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 March 31, 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 $170 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.

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Retirement Benefits (Tables)

3 Months Ended

Mar. 31, 2014

Compensation and Retirement Disclosure [Abstract]

Pension Plans and Postretirement Plans

Components of the net periodic benefit costs for the three months ended March 31, 2014 and 2013 were as follows:

Pension Plans	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power
	(in millions)
Three Months Ended March 31, 2014
Service cost	$	53		$	12		$	16		$	3		$	3
Interest cost	109			26			38			5			5
Expected return on plan assets	(161		)	(42		)	(57		)	(7		)	(7		)
Amortization:
Prior service costs	6			1			3			—			—
Net (gain)/loss	28			8			10			1			1
Net cost	$	35		$	5		$	10		$	2		$	2
Three Months Ended March 31, 2013
Service cost	$	58		$	13		$	17		$	3		$	3
Interest cost	97			23			34			4			5
Expected return on plan assets	(151		)	(39		)	(53		)	(6		)	(7		)
Amortization:
Prior service costs	7			2			3			—			—
Net (gain)/loss	50			13			19			2			2
Net cost	$	61		$	12		$	20		$	3		$	3

Postretirement Benefits	Southern Company			Alabama Power			Georgia Power			Gulf Power		Mississippi Power
	(in millions)
Three Months Ended March 31, 2014
Service cost	$	5		$	1		$	2		$	—	$	—
Interest cost	20			5			8			1		1
Expected return on plan assets	(15		)	(6		)	(6		)	—		—
Amortization:
Prior service costs	1			1			—			—		—
Net (gain)/loss	1			—			—			—		—
Net cost	$	12		$	1		$	4		$	1	$	1
Three Months Ended March 31, 2013
Service cost	$	6		$	2		$	2		$	—	$	—
Interest cost	19			5			8			1		1
Expected return on plan assets	(14		)	(6		)	(6		)	—		—
Amortization:
Transition obligation	1			—			1			—		—
Prior service costs	1			1			—			—		—
Net (gain)/loss	3			—			2			—		—
Net cost	$	16		$	2		$	7		$	1	$	1

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Stockholders' Equity - Earnings per Share (Details) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Earnings per Share
As reported shares	890	870
Effect of options and performance share award units	3	5
Diluted shares	893	875
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	17

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Fair Value Measurements (Policies)

3 Months Ended

Mar. 31, 2014

Fair Value Disclosures [Abstract]

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.