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

21

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