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 September 30, 2014

OR

¨TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number	Registrant, State of Incorporation, Address and Telephone Number	I.R.S. Employer Identification No.
1-3526	The Southern Company (A Delaware Corporation) 30 Ivan Allen Jr. Boulevard, N.W. Atlanta, Georgia 30308 (404) 506-5000	58-0690070
1-3164	Alabama Power Company (An Alabama Corporation) 600 North 18th Street Birmingham, Alabama 35203 (205) 257-1000	63-0004250
1-6468	Georgia Power Company (A Georgia Corporation) 241 Ralph McGill Boulevard, N.E. Atlanta, Georgia 30308 (404) 506-6526	58-0257110
001-31737	Gulf Power Company (A Florida Corporation) One Energy Place Pensacola, Florida 32520 (850) 444-6111	59-0276810
001-11229	Mississippi Power Company (A Mississippi Corporation) 2992 West Beach Boulevard Gulfport, Mississippi 39501 (228) 864-1211	64-0205820
333-98553	Southern Power Company (A Delaware Corporation) 30 Ivan Allen Jr. Boulevard, N.W. Atlanta, Georgia 30308 (404) 506-5000	58-2598670

Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes þ No ¨

Indicate by check mark whether the registrants have submitted electronically and posted on their corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrants were required to submit and post such files). Yes þ No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):

Registrant	Large Accelerated Filer	Accelerated Filer	Non- accelerated Filer	Smaller Reporting Company
The Southern Company	X
Alabama Power Company			X
Georgia Power Company			X
Gulf Power Company			X
Mississippi Power Company			X
Southern Power Company			X

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act.) Yes ¨ No þ (Response applicable to all registrants.)

Registrant	Description of Common Stock	Shares Outstanding at September 30, 2014
The Southern Company	Par Value $5 Per Share	899,812,716
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

September 30, 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	39
	Condensed Statements of Comprehensive Income	39
	Condensed Statements of Cash Flows	40
	Condensed Balance Sheets	41
	Management's Discussion and Analysis of Financial Condition and Results of Operations	43
	Georgia Power Company
	Condensed Statements of Income	57
	Condensed Statements of Comprehensive Income	57
	Condensed Statements of Cash Flows	58
	Condensed Balance Sheets	59
	Management's Discussion and Analysis of Financial Condition and Results of Operations	61
	Gulf Power Company
	Condensed Statements of Income	79
	Condensed Statements of Comprehensive Income	79
	Condensed Statements of Cash Flows	80
	Condensed Balance Sheets	81
	Management's Discussion and Analysis of Financial Condition and Results of Operations	83
	Mississippi Power Company
	Condensed Statements of Operations	98
	Condensed Statements of Comprehensive Income (Loss)	98
	Condensed Statements of Cash Flows	99
	Condensed Balance Sheets	100
	Management's Discussion and Analysis of Financial Condition and Results of Operations	102
	Southern Power Company and Subsidiary Companies
	Condensed Consolidated Statements of Income	129
	Condensed Consolidated Statements of Comprehensive Income	129
	Condensed Consolidated Statements of Cash Flows	130
	Condensed Consolidated Balance Sheets	131
	Management's Discussion and Analysis of Financial Condition and Results of Operations	133
	Notes to the Condensed Financial Statements	144
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	37
Item 4.	Controls and Procedures	37

3

INDEX TO QUARTERLY REPORT ON FORM 10-Q

September 30, 2014

		Page Number
	PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	189
Item 1A.	Risk Factors	189
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	189
	Signatures	192

4

DEFINITIONS

Term	Meaning
2012 MPSC CPCN Order	A detailed order issued by the Mississippi PSC in April 2012 confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing the acquisition, construction, and operation of the Kemper IGCC
2013 ARP	Alternative Rate Plan approved by the Georgia PSC for Georgia Power for the years 2014 through 2016
AFUDC	Allowance for Funds Used During Construction
Alabama Power	Alabama Power Company
ASC	Accounting Standards Codification
Baseload Act	State of Mississippi legislation designed to enhance the Mississippi PSC's authority to facilitate development and construction of baseload generation in the State of Mississippi
Chancery Court	Chancery Court of Harrison County, Mississippi
Clean Air Act	Clean Air Act Amendments of 1990
Contractor	Westinghouse and Stone & Webster, Inc.
CO2	Carbon dioxide
CPCN	Certificate of Public Convenience and Necessity
CWIP	Construction work in progress
DOE	U.S. Department of Energy
ECO Plan	Mississippi Power's Environmental Compliance Overview Plan
EPA	U.S. Environmental Protection Agency
FERC	Federal Energy Regulatory Commission
FFB	Federal Financing Bank
Form 10-K	Combined Annual Report on Form 10-K of Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power for the year ended December 31, 2013
GAAP	Generally accepted accounting principles
Georgia Power	Georgia Power Company
GHG	Greenhouse gas
Gulf Power	Gulf Power Company
IGCC	Integrated coal gasification combined cycle
IIC	Intercompany Interchange Contract
Internal Revenue Code	Internal Revenue Code of 1986, as amended
IRS	Internal Revenue Service
ITCs	Investment tax credits
Kemper IGCC	IGCC facility under construction in Kemper County, Mississippi
KWH	Kilowatt-hour
LIBOR	London Interbank Offered Rate
Mississippi Power	Mississippi Power Company
mmBtu	Million British thermal unit
Moody's	Moody's Investors Service, Inc.
MW	Megawatt
NCCR	Nuclear Construction Cost Recovery
NRC	U.S. Nuclear Regulatory Commission
OCI	Other comprehensive income

5

DEFINITIONS

(continued)

Term	Meaning
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	Alabama Power's Rate Certificated New Plant
Rate CNP Environmental	Alabama Power's Rate Certificated New Plant Environmental
Rate CNP PPA	Alabama Power's Rate Certificated New Plant Power Purchase Agreement
registrants	Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power
ROE	Return on equity
scrubber	Flue gas desulfurization system
SEC	U.S. Securities and Exchange Commission
SMEPA	South Mississippi Electric Power Association
Southern Company	The Southern Company
Southern Company system	Southern Company, the traditional operating companies, Southern Power, and other subsidiaries
Southern Nuclear	Southern Nuclear Operating Company, Inc.
Southern Power	Southern Power Company and its subsidiaries
S&P	Standard and Poor's Ratings Services, a division of The McGraw Hill Companies, Inc.
traditional operating companies	Alabama Power, Georgia Power, Gulf Power, and Mississippi Power
Vogtle Owners	Georgia Power, Oglethorpe Power Corporation, the Municipal Electric Authority of Georgia, and the City of Dalton, Georgia, an incorporated municipality in the State of Georgia acting by and through its Board of Water, Light, and Sinking Fund Commissioners
Westinghouse	Westinghouse Electric Company LLC
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 rates, the strategic goals for the wholesale business, economic recovery, fuel and environmental cost recovery and other rate actions, current and proposed environmental regulations and related compliance plans and estimated expenditures, access to sources of capital, projections for the qualified pension plan, postretirement benefit plans, and nuclear decommissioning trust fund contributions, financing activities, completion dates of construction projects, plans and estimated costs for new generation resources, filings with state and federal regulatory authorities, impact of the American Taxpayer Relief Act of 2012, estimated sales and purchases under power sale and purchase agreements, and estimated construction and other capital expenditures. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "could," "should," "expects," "plans," "anticipates," "believes," "estimates," "projects," "predicts," "potential," or "continue" or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:

• the impact of recent and future federal and state regulatory changes, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, environmental laws including regulation of water, coal combustion residuals, and emissions of sulfur, nitrogen, CO₂, soot, particulate matter, hazardous air pollutants, including mercury, and other substances, and also changes in tax and other laws and regulations to which Southern Company and its subsidiaries are subject, as well as changes in application of existing laws and regulations;

• current and future litigation, regulatory investigations, proceedings, or inquiries, including pending EPA civil actions against certain Southern Company subsidiaries, FERC matters, and IRS and state tax audits;

• the effects, extent, and timing of the entry of additional competition in the markets in which Southern Company's subsidiaries operate;

• variations in demand for electricity, including those relating to weather, the general economy and recovery from the last recession, population and business growth (and declines), the effects of energy conservation measures, including from the development and deployment of alternative energy sources such as self-generation and distributed generation technologies, and any potential economic impacts resulting from federal fiscal decisions;

• available sources and costs of fuels;

• effects of inflation;

• ability to control costs and avoid cost overruns during the development and construction of facilities, which include the development and construction of generating facilities with designs that have not been finalized or previously constructed, including changes in labor costs and productivity factors, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under construction or other agreements, operational performance, operational readiness, including specialized operator training, unforeseen engineering or design problems, delays associated with start-up activities (including major equipment failure and system integration), and/or operations;

• ability to construct facilities in accordance with the requirements of permits and licenses, to satisfy any operational and environmental performance standards, including any PSC requirements and the requirements of tax credits and other incentives, and to integrate facilities into the Southern Company system upon completion of construction;

• investment performance of Southern Company's employee and retiree benefit plans and the Southern Company system's nuclear decommissioning trust funds;

• advances in technology;

• state and federal rate regulations and the impact of pending and future rate cases and negotiations, including rate actions relating to fuel and other cost recovery mechanisms;

• legal proceedings and regulatory approvals and actions related to Plant Vogtle Units 3 and 4, including Georgia PSC approvals and NRC actions and related legal proceedings involving the commercial parties;

• actions related to cost recovery for the Kemper IGCC, including actions relating to proposed securitization, Mississippi PSC approval of Mississippi Power's proposed rate recovery plan, as ultimately amended, which currently includes the ability to complete the proposed sale of an interest in the Kemper IGCC to SMEPA, the ability to utilize bonus depreciation, which currently requires that assets be placed in service in 2014, and satisfaction of requirements to utilize ITCs and grants;

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

7

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

(continued)

• the outcome of any legal or regulatory proceedings regarding any settlement agreement between Mississippi Power and the Mississippi PSC, the March 2013 rate order approving retail rate increases consistent with the terms of any settlement agreement, 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's 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 September 30,						For the Nine Months Ended September 30,
	2014			2013			2014			2013
	(in millions)						(in millions)
Operating Revenues:
Retail revenues	$	4,558		$	4,319		$	12,186		$	11,237
Wholesale revenues	600			520			1,719			1,406
Other electric revenues	169			166			503			477
Other revenues	12			12			42			40
Total operating revenues	5,339			5,017			14,450			13,160
Operating Expenses:
Fuel	1,656			1,580			4,765			4,216
Purchased power	194			145			514			367
Other operations and maintenance	1,021			928			3,026			2,849
Depreciation and amortization	514			480			1,515			1,422
Taxes other than income taxes	258			243			751			710
Estimated loss on Kemper IGCC	418			150			798			1,140
Total operating expenses	4,061			3,526			11,369			10,704
Operating Income	1,278			1,491			3,081			2,456
Other Income and (Expense):
Allowance for equity funds used during construction	63			53			182			139
Interest expense, net of amounts capitalized	(207		)	(202		)	(623		)	(628		)
Other income (expense), net	(7		)	(5		)	(20		)	(31		)
Total other income and (expense)	(151		)	(154		)	(461		)	(520		)
Earnings Before Income Taxes	1,127			1,337			2,620			1,936
Income taxes	392			468			889			657
Consolidated Net Income	735			869			1,731			1,279
Dividends on Preferred and Preference Stock of Subsidiaries	17			17			51			49
Consolidated Net Income After Dividends on Preferred and Preference Stock of Subsidiaries	$	718		$	852		$	1,680		$	1,230
Common Stock Data:
Earnings per share (EPS) -
Basic EPS	$	0.80		$	0.97		$	1.88		$	1.41
Diluted EPS	$	0.80		$	0.97		$	1.87		$	1.40
Average number of shares of common stock outstanding (in millions)
Basic	898			878			894			874
Diluted	902			881			898			879
Cash dividends paid per share of common stock	$	0.5250		$	0.5075		$	1.5575		$	1.5050

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 September 30,						For the Nine Months Ended September 30,
	2014			2013			2014			2013
	(in millions)						(in millions)
Consolidated Net Income	$	735		$	869		$	1,731		$	1,279
Other comprehensive income (loss):
Qualifying hedges:
Reclassification adjustment for amounts included in net income, net of tax of $1, $1, $2 and $5, respectively	1			1			4			7
Pension and other post retirement benefit plans:
Reclassification adjustment for amounts included in net income, net of tax of $1, $1, $2 and $3, respectively	1			1			2			4
Total other comprehensive income (loss)	2			2			6			11
Dividends on preferred and preference stock of subsidiaries	(17		)	(17		)	(51		)	(49		)
Comprehensive Income	$	720		$	854		$	1,686		$	1,241

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 Nine Months Ended September 30,
	2014			2013
	(in millions)
Operating Activities:
Consolidated net income	$	1,731		$	1,279
Adjustments to reconcile consolidated net income to net cash provided from operating activities —
Depreciation and amortization, total	1,798			1,725
Deferred income taxes	330			263
Allowance for equity funds used during construction	(182		)	(139		)
Stock based compensation expense	51			48
Estimated loss on Kemper IGCC	798			1,140
Other, net	(74		)	76
Changes in certain current assets and liabilities —
-Receivables	(640		)	(407		)
-Fossil fuel stock	522			471
-Materials and supplies	(45		)	33
-Other current assets	(29		)	(1		)
-Accounts payable	(92		)	(140		)
-Accrued taxes	403			268
-Accrued compensation	96			(198		)
-Other current liabilities	20			(7		)
Net cash provided from operating activities	4,687			4,411
Investing Activities:
Property additions	(3,903		)	(3,978		)
Investment in restricted cash	(11		)	(169		)
Distribution of restricted cash	37			94
Nuclear decommissioning trust fund purchases	(635		)	(744		)
Nuclear decommissioning trust fund sales	633			742
Cost of removal, net of salvage	(106		)	(90		)
Prepaid long-term service agreement	(145		)	(79		)
Other investing activities	(27		)	122
Net cash used for investing activities	(4,157		)	(4,102		)
Financing Activities:
Decrease in notes payable, net	(1,117		)	(70		)
Proceeds —
Long-term debt issuances	2,715			2,421
Interest-bearing refundable deposit	75			—
Preference stock	—			50
Common stock issuances	484			479
Redemptions —
Long-term debt	(437		)	(1,767		)
Common stock repurchased	(5		)	(19		)
Payment of common stock dividends	(1,391		)	(1,314		)
Payment of dividends on preferred and preference stock of subsidiaries	(51		)	(49		)
Other financing activities	(48		)	14
Net cash provided from (used for) financing activities	225			(255		)
Net Change in Cash and Cash Equivalents	755			54
Cash and Cash Equivalents at Beginning of Period	659			628
Cash and Cash Equivalents at End of Period	$	1,414		$	682
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $80 and $67 capitalized for 2014 and 2013, respectively)	$	560		$	564
Income taxes, net	263			149
Noncash transactions — accrued property additions at end of period	415			539
Noncash transactions — capital lease obligation	—			83

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 September 30, 2014			At December 31, 2013
	(in millions)
Current Assets:
Cash and cash equivalents	$	1,414		$	659
Receivables —
Customer accounts receivable	1,439			1,027
Unbilled revenues	476			448
Under recovered regulatory clause revenues	104			58
Other accounts and notes receivable	259			304
Accumulated provision for uncollectible accounts	(20		)	(18		)
Fossil fuel stock, at average cost	817			1,339
Materials and supplies, at average cost	1,018			959
Vacation pay	170			171
Prepaid expenses	387			489
Other regulatory assets, current	147			124
Other current assets	47			39
Total current assets	6,258			5,599
Property, Plant, and Equipment:
In service	68,545			66,021
Less accumulated depreciation	23,846			23,059
Plant in service, net of depreciation	44,699			42,962
Other utility plant, net	218			240
Nuclear fuel, at amortized cost	840			855
Construction work in progress	7,410			7,151
Total property, plant, and equipment	53,167			51,208
Other Property and Investments:
Nuclear decommissioning trusts, at fair value	1,510			1,465
Leveraged leases	680			665
Miscellaneous property and investments	245			218
Total other property and investments	2,435			2,348
Deferred Charges and Other Assets:
Deferred charges related to income taxes	1,488			1,432
Prepaid pension costs	438			419
Unamortized debt issuance expense	206			139
Unamortized loss on reacquired debt	274			293
Other regulatory assets, deferred	2,624			2,557
Other deferred charges and assets	764			551
Total deferred charges and other assets	5,794			5,391
Total Assets	$	67,654		$	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 September 30, 2014			At December 31, 2013
	(in millions)
Current Liabilities:
Securities due within one year	$	2,398		$	469
Interest-bearing refundable deposit	225			150
Notes payable	361			1,482
Accounts payable	1,381			1,376
Customer deposits	386			380
Accrued taxes —
Accrued income taxes	238			13
Other accrued taxes	558			456
Accrued interest	270			251
Accrued vacation pay	213			217
Accrued compensation	423			303
Other regulatory liabilities, current	84			92
Other current liabilities	353			347
Total current liabilities	6,890			5,536
Long-term Debt	21,699			21,344
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	10,817			10,563
Deferred credits related to income taxes	191			202
Accumulated deferred investment tax credits	1,006			966
Employee benefit obligations	1,474			1,461
Asset retirement obligations	2,133			2,006
Other cost of removal obligations	1,341			1,270
Other regulatory liabilities, deferred	566			475
Other deferred credits and liabilities	549			584
Total deferred credits and other liabilities	18,077			17,527
Total Liabilities	46,666			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 — September 30, 2014: 901 million shares
— December 31, 2013: 893 million shares
Treasury — September 30, 2014: 0.7 million shares
— December 31, 2013: 5.7 million shares
Par value	4,500			4,461
Paid-in capital	5,652			5,362
Treasury, at cost	(25		)	(250		)
Retained earnings	9,800			9,510
Accumulated other comprehensive loss	(70		)	(75		)
Total Common Stockholders' Equity	19,857			19,008
Preferred and Preference Stock of Subsidiaries	756			756
Total Stockholders' Equity	20,613			19,764
Total Liabilities and Stockholders' Equity	$	67,654		$	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

THIRD QUARTER 2014 vs. THIRD QUARTER 2013

AND

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

OVERVIEW

Southern Company is a holding company that owns all of the common stock of the traditional operating companies – Alabama Power, Georgia Power, Gulf Power, and Mississippi Power – and Southern Power and other direct and indirect subsidiaries. Discussion of the results of operations is focused on the Southern Company system's primary business of electricity sales by the traditional operating companies and Southern Power. The four traditional operating companies are vertically integrated utilities providing electric service in four Southeastern states. Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company's other business activities include investments in leveraged lease projects and telecommunications. For additional information on these businesses, see BUSINESS – "The Southern Company System – Traditional Operating Companies," "Southern Power," and "Other Businesses" in Item 1 of the Form 10-K.

In addition, subsidiaries of Southern Company are constructing Plant Vogtle Units 3 and 4 (45.7% ownership interest by Georgia Power in two units, each with approximately 1,100 MWs) and the Kemper IGCC (in which Mississippi Power is ultimately expected to hold an 85% ownership interest in the 582-MW facility). See RESULTS OF OPERATIONS – "Estimated Loss on Kemper IGCC," FUTURE EARNINGS POTENTIAL – "Construction Program," and Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" and "Integrated Coal Gasification Combined Cycle" herein for additional information.

Southern Company continues to focus on several key performance indicators. These indicators include customer satisfaction, plant availability, system reliability, execution of major construction projects, and earnings per share. For additional information on these indicators, see MANAGEMENT'S DISCUSSION AND ANALYSIS – OVERVIEW – "Key Performance Indicators" of Southern Company in Item 7 of the Form 10-K. See Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for information regarding revisions to the cost estimate for the Kemper IGCC that have negatively impacted Southern Company's earnings per share, one of its key performance indicators, for 2014, as compared to the target.

RESULTS OF OPERATIONS

Net Income

Third Quarter 2014 vs. Third Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$(134)	(15.7)	$450	36.6

Southern Company's third quarter 2014 net income after dividends on preferred and preference stock of subsidiaries was $718 million ($0.80 per share) compared to $852 million ($0.97 per share) for the third quarter 2013. The decrease was primarily the result of a $418 million pre-tax charge ($258 million after tax) recorded in the third quarter 2014 compared to a $150 million pre-tax charge ($93 million after tax) recorded in the third quarter 2013 for revisions of estimated costs expected to be incurred on Mississippi Power's construction of the Kemper IGCC, as well as increases in non-fuel operations and maintenance expenses. The decrease was partially offset by an increase in revenues due to retail base rate increases and warmer weather in the third quarter 2014 as compared to the corresponding period in 2013.

Southern Company's year-to-date 2014 net income after dividends on preferred and preference stock of subsidiaries was $1.7 billion ($1.88 per share) compared to $1.2 billion ($1.41 per share) for the corresponding period in 2013. The increase was primarily the result of $798 million in pre-tax charges ($493 million after tax) recorded year-to-

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

date 2014 compared to $1.1 billion in pre-tax charges ($704 million after tax) recorded year-to-date 2013 for revisions of estimated costs expected to be incurred on Mississippi Power's construction of the Kemper IGCC. The increase was also related to an increase in revenues due to retail base rate increases as well as colder weather in the first quarter 2014 and warmer weather in the second and third quarters 2014 as compared to the corresponding periods in 2013, partially offset by increases in non-fuel operations and maintenance expenses.

Retail Revenues

Third Quarter 2014 vs. Third Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$239	5.5	$949	8.4

In the third quarter 2014, retail revenues were $4.6 billion compared to $4.3 billion for the corresponding period in 2013. For year-to-date 2014, retail revenues were $12.2 billion compared to $11.2 billion for the corresponding period in 2013.

Details of the changes in retail revenues were as follows:

	Third  Quarter 2014				Year-to-Date  2014
	(in millions)		(% change)		(in millions)		(% change)
Retail – prior year	$	4,319			$	11,237
Estimated change resulting from –
Rates and pricing	89		2.1		242		2.1
Sales growth	9		0.2		29		0.3
Weather	87		2.0		238		2.1
Fuel and other cost recovery	54		1.2		440		3.9
Retail – current year	$	4,558	5.5	%	$	12,186	8.4	%

Revenues associated with changes in rates and pricing increased in the third quarter and year-to-date 2014 when compared to the corresponding periods in 2013 primarily due to retail rate increases at all of the traditional operating companies. The increases in revenues at Georgia Power were primarily due to base tariff increases effective January 1, 2014, as approved by the Georgia PSC in the 2013 ARP, and increases in collections for financing costs related to the construction of Plant Vogtle Units 3 and 4 through the NCCR tariff as well as higher contributions from market-driven rates from commercial and industrial customers. Also contributing to the increases were increased revenues at Alabama Power associated with Rate CNP Environmental primarily resulting from the inclusion of pre-2005 environmental assets and increased revenues at Gulf Power primarily resulting from the retail base rate increase effective January 2014, as approved by the Florida PSC. In addition, the year-to-date 2014 increase also reflects increased revenues at Mississippi Power related to the collection of Kemper IGCC cost recovery revenues, the majority of which were deferred to a regulatory liability, and a PEP base rate increase, which both became effective in March 2013.

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 third quarter and year-to-date 2014 when compared to the corresponding periods in 2013. Industrial KWH energy sales increased 4.8% in the third quarter and 3.6% for year-to-date 2014 primarily due to increased sales in the primary metals, chemicals, paper, non-manufacturing, transportation, and stone, clay, and glass sectors. Weather-adjusted commercial KWH energy sales decreased 1.1% in the third quarter and 0.5% for year-to-date 2014 primarily due to decreased customer usage, partially offset by

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

customer growth. Weather-adjusted residential KWH sales remained relatively flat in the third quarter and for year-to-date 2014 as a result of customer growth offset by decreased customer usage. Household income, one of the primary drivers of residential customer usage, has been flat in 2014.

Fuel and other cost recovery revenues increased $54 million in the third quarter 2014 when compared to the corresponding period in 2013 primarily due to increased energy sales as a result of warmer weather in the third quarter 2014 as compared to the corresponding period in 2013. Fuel and other cost recovery revenues increased $440 million for year-to-date 2014 when compared to the corresponding period in 2013 primarily due to higher natural gas prices and increased energy sales as a result of colder weather in the first quarter 2014 and warmer weather in the second and third quarters 2014 as compared to the corresponding periods in 2013.

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

Third Quarter 2014 vs. Third Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$80	15.4	$313	22.3

Wholesale revenues consist of PPAs primarily with investor-owned utilities and electric cooperatives and short-term opportunity sales. Wholesale revenues from PPAs have both capacity and energy components. Capacity revenues reflect the recovery of fixed costs and a return on investment. Energy revenues will vary depending on fuel prices, the market prices of wholesale energy compared to the Southern Company system's generation, demand for energy within the Southern Company system's service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. Short-term opportunity sales are made at market-based rates that generally provide a margin above the Southern Company system's variable cost to produce the energy.

In the third quarter 2014, wholesale revenues were $600 million compared to $520 million for the corresponding period in 2013 primarily related to an $82 million increase in energy revenues. The increase in energy revenues was primarily related to new solar PPAs and requirements contracts and increased revenue under existing contracts primarily at Southern Power, as well as an increase in KWH sales resulting from utilization of the Southern Company system's lower cost generation.

For year-to-date 2014, wholesale revenues were $1.7 billion compared to $1.4 billion for the corresponding period in 2013, reflecting a $303 million increase in energy revenues and a $10 million increase in capacity revenues. The increase in energy revenues was primarily related to increased revenue under existing contracts as well as new solar PPAs and requirements contracts primarily at Southern Power, 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. The increase in capacity revenues was primarily due to wholesale base rate increases at Mississippi Power, partially offset by a decrease in capacity revenues at Southern Power.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Other Electric Revenues

Third Quarter 2014 vs. Third Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$3	1.8	$26	5.5

For year-to-date 2014, other electric revenues were $503 million compared to $477 million for the corresponding period in 2013. The increase was primarily due to a $19 million increase in open access transmission tariff revenues at Alabama Power and Georgia Power and a $6 million increase in solar application fee revenue at Georgia Power.

Fuel and Purchased Power Expenses

	Third Quarter 2014 vs. Third Quarter 2013			Year-to-Date 2014 vs. Year-to-Date 2013
	(change in millions)		(% change)	(change in millions)		(% change)
Fuel	$	76	4.8	$	549	13.0
Purchased power	49		33.8	147		40.1
Total fuel and purchased power expenses	$	125		$	696

In the third quarter 2014, total fuel and purchased power expenses were $1.9 billion compared to $1.7 billion for the corresponding period in 2013. The increase was primarily the result of a $139 million increase in the volume of KWHs generated primarily due to increased demand resulting from warmer weather in the third quarter 2014 compared to the corresponding period in 2013, a $41 million increase in the average cost of purchased power, and a $16 million increase in the volume of KWHs purchased, partially offset by a $71 million decrease in the average cost of fuel primarily due to lower coal prices.

For year-to-date 2014, total fuel and purchased power expenses were $5.3 billion compared to $4.6 billion for the corresponding period in 2013. The increase was primarily the result of a $439 million increase in the volume of KWHs generated primarily due to increased demand resulting from colder weather in the first quarter 2014 and warmer weather in the second and third quarters 2014 compared to the corresponding periods in 2013 and a $298 million increase in the average cost of fuel and purchased power primarily due to higher natural gas prices. These increases were partially offset by a $41 million decrease in the volume of KWHs purchased as the marginal cost of the Southern Company system's generation available was lower than the market cost of available energy.

Fuel and purchased power energy transactions at the traditional operating companies are generally offset by fuel revenues and do not have a significant impact on net income. See FUTURE EARNINGS POTENTIAL – "PSC Matters – Retail Fuel Cost Recovery" herein for additional information. Fuel expenses incurred under Southern Power's PPAs are generally the responsibility of the counterparties and do not significantly impact net income.

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

	Third Quarter 2014	Third Quarter 2013	Year-to-Date 2014	Year-to-Date 2013
Total generation (billions of KWHs)	54	50	147	136
Total purchased power (billions of KWHs)	3	3	9	10
Sources of generation (percent) —
Coal	44	44	45	40
Nuclear	15	16	16	17
Gas	40	37	36	39
Hydro	1	3	3	4
Cost of fuel, generated (cents per net KWH) —
Coal	3.63	4.06	3.87	4.08
Nuclear	0.84	0.87	0.87	0.87
Gas	3.42	3.27	3.77	3.30
Average cost of fuel, generated (cents per net KWH)	3.13	3.24	3.34	3.21
Average cost of purchased power (cents per net KWH)(a)	6.77	5.66	7.60	5.22

(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 third quarter 2014, fuel expense was $1.7 billion compared to $1.6 billion for the corresponding period in 2013. The increase was primarily due to a 68.3% decrease in the volume of KWHs generated by hydro facilities resulting from less rainfall and a 9.9% increase in the volume of KWHs generated by fossil fuel, partially offset by a 10.6% decrease in the average cost of coal per KWH generated.

For year-to-date 2014, fuel expense was $4.8 billion compared to $4.2 billion for the corresponding period in 2013. The increase was primarily due to a 21.6% increase in the volume of KWHs generated by coal, a 14.2% increase in the average cost of natural gas per KWH generated, and a 31.5% decrease in the volume of KWHs generated by hydro facilities resulting from less rainfall.

Purchased Power

In the third quarter 2014, purchased power expense was $194 million compared to $145 million for the corresponding period in 2013. The increase was primarily due to a 19.6% increase in the average cost per KWH purchased primarily as a result of higher natural gas prices and an 8.3% increase in the volume of KWHs purchased primarily as a result of increased demand from warmer weather in the third quarter 2014 as compared to the corresponding period in 2013.

For year-to-date 2014, purchased power expense was $514 million compared to $367 million for the corresponding period in 2013. The increase was primarily due to a 45.6% increase in the average cost per KWH purchased, partially offset by an 8.3% decrease in the volume of KWHs purchased as the marginal cost of the Southern Company system's generation available was lower than the market cost of available energy primarily due to higher natural gas prices.

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

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Other Operations and Maintenance Expenses

Third Quarter 2014 vs. Third Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$93	10.0	$177	6.2

In the third quarter 2014, other operations and maintenance expenses were $1.0 billion compared to $928 million for the corresponding period in 2013. The increase was primarily due to a $30 million increase in transmission and distribution costs primarily related to overhead line maintenance, a $29 million increase in scheduled outage and maintenance costs at generation facilities, a $14 million increase in commodity and contract labor costs, a $12 million net increase in employee compensation and benefits including pension costs, and a $6 million increase in customer accounts, service, and sales costs primarily related to customer incentive and demand side management programs. The increase in scheduled outage and maintenance costs was partially offset by a $16 million deferral of certain non-nuclear outage expenditures under an accounting order at Alabama Power.

For year-to-date 2014, other operations and maintenance expenses were $3.0 billion compared to $2.8 billion for the corresponding period in 2013. The increase was primarily due to an $80 million increase in scheduled outage and maintenance costs at generation facilities, a $53 million increase in transmission and distribution costs primarily related to overhead line maintenance, a $29 million increase in commodity and contract labor costs, a $15 million net increase in employee compensation and benefits including pension costs, a $10 million increase in customer accounts, service, and sales costs primarily related to customer incentive and demand-side management programs, and a $7 million increase in litigation expense. The increase in scheduled outage and maintenance costs was partially offset by a $57 million deferral of certain non-nuclear outage expenditures under an accounting order at Alabama Power.

See Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Alabama Power – Non-Nuclear Outage Accounting Order" in Item 8 of the Form 10-K for additional information related to non-nuclear outage expenditures. Also see Note (F) to the Condensed Financial Statements herein for additional information related to pension costs.

Depreciation and Amortization

Third Quarter 2014 vs. Third Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$34	7.1	$93	6.5

In the third quarter 2014, depreciation and amortization was $514 million compared to $480 million for the corresponding period in 2013. For year-to-date 2014, depreciation and amortization was $1.5 billion compared to $1.4 billion for the corresponding period in 2013. The increases were primarily due to an increase in plant in service at Southern Power related to the additions of solar facilities in 2013 and 2014 and additional component depreciation at Southern Power as a result of production being greater during the summer months, as well as the completion of amortization of a regulatory liability related to state income tax credits in December 2013 at Georgia Power. Also contributing to the year-to-date increase was an increase in depreciation rates related to environmental assets at Alabama Power. These increases were partially offset by a decrease in depreciation and amortization at Georgia Power, as authorized in the 2013 ARP. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Alabama Power – Rate CNP" of Southern Company in Item 7 of the Form 10-K for additional information regarding Alabama Power's revision to Rate CNP Environmental. Also see Note (A) to the Condensed Financial Statements under "Depreciation" herein for additional information related to component depreciation at Southern Power.

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Taxes Other Than Income Taxes

Third Quarter 2014 vs. Third Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$15	6.2	$41	5.8

In the third quarter 2014, taxes other than income taxes were $258 million compared to $243 million for the corresponding period in 2013. For year-to-date 2014, taxes other than income taxes were $751 million compared to $710 million for the corresponding period in 2013. The increases were primarily the result of increases of $7 million and $29 million in municipal franchise fees related to higher retail revenues in 2014 and $5 million and $9 million in payroll taxes primarily related to higher employee benefits in the third quarter and year-to-date 2014, respectively.

Estimated Loss on Kemper IGCC

Third Quarter 2014 vs. Third Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$268	N/M	$(342)	(30.0)

N/M – Not meaningful

In the third quarter 2014 and 2013, estimated probable losses on the Kemper IGCC of $418 million and $150 million, respectively, were recorded at Southern Company. For year-to-date 2014 and 2013, estimated probable losses on the Kemper IGCC of $798 million and $1.1 billion, respectively, were recorded at Southern Company. These losses reflect revisions of estimated costs expected to be incurred on Mississippi Power's construction of the Kemper IGCC in excess of the $2.88 billion cost cap established by the Mississippi PSC, net of $245 million of grants awarded to the project by the DOE under the Clean Coal Power Initiative Round 2 (DOE Grants) and excluding the cost of the lignite mine and equipment, the cost of the CO₂ pipeline facilities, AFUDC, and certain general exceptions, including change of law, force majeure, and beneficial capital (which exists when Mississippi Power demonstrates that the purpose and effect of the construction cost increase is to produce efficiencies that will result in a neutral or favorable effect on customers relative to the original proposal for the CPCN) (Cost Cap Exceptions). See FUTURE EARNINGS POTENTIAL – "Construction Program" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.

Allowance for Equity Funds Used During Construction

Third Quarter 2014 vs. Third Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$10	18.9	$43	30.9

In the third quarter 2014, AFUDC equity was $63 million compared to $53 million for the corresponding period in 2013. The increase was primarily related to additional capital expenditures at Alabama Power.

For year-to-date 2014, AFUDC equity was $182 million compared to $139 million for the corresponding period in 2013. The increase was primarily due to an increase in CWIP related to Mississippi Power's Kemper IGCC and additional capital expenditures at Alabama Power. See Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information regarding the Kemper IGCC.

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Interest Expense, Net of Amounts Capitalized

Third Quarter 2014 vs. Third Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$5	2.5	$(5)	(0.8)

In the third quarter 2014, interest expense, net of amounts capitalized was $207 million compared to $202 million in the corresponding period in 2013. The increase was primarily due to a $17 million increase related to a higher amount of outstanding long-term debt, partially offset by a $12 million decrease related to the refinancing of long-term debt at lower rates.

For year-to-date 2014, interest expense, net of amounts capitalized was $623 million compared to $628 million in the corresponding period in 2013. The decrease was primarily due to a $30 million decrease related to the refinancing of long-term debt at lower rates and a $13 million increase in capitalized interest, partially offset by a $34 million increase related to a higher amount of outstanding long-term debt and a $7 million increase in interest expense resulting from the deposit received by Mississippi Power in January 2014 related to SMEPA's pending purchase of an undivided interest in the Kemper IGCC. See Note (E) to the Condensed Financial Statements herein for additional information.

Other Income (Expense), Net

Third Quarter 2014 vs. Third Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$(2)	N/M	$11	35.5

N/M – Not meaningful

For year-to-date 2014, other income (expense), net was $(20) million compared to $(31) million for the corresponding period in 2013. The decrease in expense was primarily due to a $26 million charge related to the restructuring of a leveraged lease investment in the first quarter 2013, partially offset by a $7 million charge related to a settlement with the Sierra Club at Mississippi Power in 2014. See Note (B) to the Condensed Financial Statements under "Other Matters – Sierra Club Settlement Agreement" herein for additional information.

Income Taxes

Third Quarter 2014 vs. Third Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$(76)	(16.2)	$232	35.3

In the third quarter 2014, income taxes were $392 million compared to $468 million for the corresponding period in 2013. The decrease was primarily due to higher tax benefits in 2014 related to the estimated probable losses recorded on Mississippi Power's construction of the Kemper IGCC, partially offset by higher pre-tax earnings.

For year-to-date 2014, income taxes were $889 million compared to $657 million for the corresponding period in 2013. The increase was primarily due to higher pre-tax earnings and lower tax benefits in 2014 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

22

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

completion and subsequent operation of the Kemper IGCC and Plant Vogtle Units 3 and 4 as well as other ongoing construction projects. Another major factor is the profitability of the competitive wholesale business. Future earnings for the electricity business in the near term will depend, in part, upon maintaining and growing sales which is subject to a number of factors. These factors include weather, competition, new energy contracts with other utilities and other wholesale customers, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in the service territory. In addition, the level of future earnings for the wholesale business also depends on numerous factors including creditworthiness of customers, total generating capacity available and related costs, future acquisitions and construction of generating facilities, and the successful remarketing of capacity as current contracts expire. Changes in regional and global economic conditions may impact sales for the traditional operating companies and Southern Power as the pace of the economic recovery remains uncertain. The timing and extent of the economic recovery will impact growth and may impact future earnings. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Southern Company in Item 7 of the Form 10-K.

Environmental Matters

Compliance costs related to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively affect results of operations, cash flows, and financial condition. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under "Environmental Matters" in Item 8 of the Form 10-K for additional information.

Environmental Statutes and Regulations

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

Air Quality

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

On April 29, 2014, the U.S. Supreme Court overturned the U.S. Court of Appeals for the District of Columbia Circuit's August 2012 decision to vacate CSAPR and remanded the case back to the U.S. Court of Appeals for the District of Columbia Circuit for further proceedings. On October 23, 2014, the U.S. Court of Appeals for the District of Columbia Circuit granted the EPA's motion to lift the stay on CSAPR implementation and approved a revised schedule under which the first phase of the rule will go into effect beginning January 1, 2015. The Southern Company system has developed and continually updates a comprehensive environmental compliance strategy to assess compliance obligations associated with current and proposed environmental requirements, including CSAPR. The ultimate financial and unit operational impact of the rule cannot be determined at this time and is dependent on the outcome of further legal proceedings, the manner in which the EPA and the states implement the final rule, and the development of related emissions allowance markets.

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

On September 17, 2014, the EPA published a supplemental proposal for the SSM rule. The EPA previously entered into a revised settlement agreement requiring the EPA to finalize the proposed rules by May 22, 2015. The proposed rule would require states subject to the rule (including Alabama, Florida, Georgia, Mississippi, and North Carolina) to revise their SSM provisions within 18 months after issuance of the final rule. The ultimate impact of the proposed SSM rule will depend on the specific provisions of the final rule, the development and implementation of rules at the state level, and the outcome of any legal challenges and cannot be determined at this time.

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

Water Quality

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

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

On August 15, 2014, the EPA published a final rule establishing standards for reducing effects on fish and other aquatic life caused by new and existing cooling water intake structures at existing power plants and manufacturing facilities, which became effective October 14, 2014. The ultimate outcome of this final rule will depend on the results of additional studies and implementation of the rule by state regulators, but could result in additional capital and operational costs associated with changes to existing intake structures and cooling systems and increased costs associated with the construction of new generating units. The ultimate impact of this rule will depend on the outcome of any legal challenges and cannot be determined at this time.

Global Climate Issues

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

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

On October 28, 2014, the EPA issued a notice of data availability related to the proposed Clean Power Plan, which was not intended to revise the EPA's proposal but to provide the public with an opportunity to consider and comment on technical issues and data related to the guidelines. The Southern Company system expects to file comments with the EPA at or prior to the EPA's December 1, 2014 extended deadline. These comments may include a preliminary estimated cost of complying with the proposed guidelines utilizing one of the EPA's compliance scenarios. These costs could be significant to the utility industry and the Southern Company system. However, the

24

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

ultimate financial and operational impact of the Clean Power Plan proposed guidelines on the Southern Company system cannot be determined at this time and will be dependent upon numerous factors. These factors include: the structure, timing, and content of the EPA's final guidelines; individual state implementation of these guidelines, including the potential that state implementation plans impose different standards; additional rulemaking activities in response to legal challenges and court decisions; the impact of future changes in generation and emissions-related technology and costs; the impact of future decisions regarding unit retirement and replacement, including the type and amount of any such replacement capacity; and the time periods over which compliance will be required.

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

PSC Matters

Retail Fuel Cost Recovery

The traditional operating companies each have established fuel cost recovery rates approved by their respective state PSCs. Fuel cost recovery revenues are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on Southern Company's revenues or net income, but will affect cash flow. The traditional operating companies continuously monitor their under or over recovered fuel cost balances. At September 30, 2014, Georgia Power, Gulf Power, and Mississippi Power had total under recovered fuel costs included on Southern Company's Condensed Balance Sheet herein of approximately $230 million. At December 31, 2013, Gulf Power had under recovered fuel costs included on Southern Company's Condensed Balance Sheet herein of approximately $21 million. The total over recovered fuel balance at Alabama Power included on Southern Company's Condensed Balance Sheet herein was approximately $44 million at September 30, 2014 compared to the total over recovered fuel balance at Alabama Power, Georgia Power, and Mississippi Power at December 31, 2013 of approximately $115 million.

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

Alabama Power

Environmental Accounting Order

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

As part of its environmental compliance strategy, Alabama Power plans to retire Plant Gorgas Units 6 and 7. These units represent 200 MWs of Alabama Power's approximately 12,200 MWs of generating capacity. Alabama Power also plans to cease using coal at Plant Barry Units 1 and 2 (250 MWs), but such units will remain available on a limited basis with natural gas as the fuel source. Additionally, Alabama Power expects to cease using coal at Plant Barry Unit 3 (225 MWs) and Plant Greene County Units 1 and 2 (300 MWs) and begin operating those units solely on natural gas. These plans are expected to be effective no later than April 2016.

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

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Nuclear Waste Fund Accounting Order

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

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

Cost of Removal Accounting Order

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Alabama Power" of Southern Company in Item 7 of the Form 10-K regarding the previously approved compliance and pension costs accounting order and non-nuclear outage accounting order.

On November 3, 2014, the Alabama PSC issued an accounting order authorizing Alabama Power to fully amortize the balances in certain regulatory asset accounts, projected to be $120 million at December 31, 2014. This amortization expense will be offset by the amortization of up to $120 million of the regulatory liability for other cost of removal obligations. The regulatory asset account balances to be fully amortized as of December 31, 2014 represent costs deferred under the compliance and pension cost accounting order as well as the non-nuclear outage accounting order, which were approved by the Alabama PSC in November 2012 and August 2013, respectively. This accounting order also requires Alabama Power to terminate, as of December 31, 2014, the regulatory asset accounts created pursuant to the compliance and pension cost accounting order and the non-nuclear outage accounting order. Consequently, Alabama Power will not defer any expenditures in 2015, 2016, and 2017 related to critical electric infrastructure and domestic nuclear facilities under these orders.

Georgia Power

Rate Plans

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Georgia Power – Rate Plans" of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Georgia Power – Rate Plans" in Item 8 of the Form 10-K for additional information on Georgia Power's 2013 ARP.

In accordance with the terms of the 2013 ARP, on October 3, 2014, Georgia Power filed the following tariff adjustments with the Georgia PSC to become effective January 1, 2015 pending its approval:

• Increase the traditional base tariffs by approximately $107 million to cover additional capacity costs;

• Increase the environmental compliance cost recovery tariff by approximately $32 million;

• Increase the demand-side management tariffs by approximately $3 million; and

• Increase the municipal franchise fee tariff by approximately $3 million, consistent with the adjustments above.

See Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" in Item 8 of the Form 10-K for additional information on Georgia Power's NCCR tariff. On October 31, 2014, Georgia Power filed to increase the NCCR tariff by approximately $27 million effective January

26

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

1, 2015 pending Georgia PSC approval. See Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" herein for additional information.

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

Renewables Development

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

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

As a result of biomass PPA amendments executed by Georgia Power during 2014, total estimated purchased power contractual obligations decreased $392 million from December 31, 2013. Estimated purchased power contractual obligations have been updated for Southern Company to $669million for 2015 and 2016, $757 million for 2017 and 2018, and $3.9 billion after 2018. Estimated purchased power contractual obligations did not change for 2014. The counterparties of the aforementioned PPAs have posted collateral as required. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations – Contractual Obligations" of Southern Company in Item 7 of the Form 10-K for additional information.

On October 8, 2014, Georgia Power executed PPAs to purchase energy from 515 MWs of solar capacity as part of the Georgia Power Advanced Solar Initiative program. These PPAs are expected to commence in 2015 and 2016, have terms ranging from 20 to 30 years, and are subject to Georgia PSC approval.

On October 23, 2014, the Georgia PSC approved Georgia Power's request to build, own, and operate three 30-MW solar generation facilities at three U.S. Army bases by the end of 2016. In addition, Georgia Power has entered into a memorandum of understanding with the U.S. Navy to pursue a similar solar project pending Georgia PSC review.

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

Integrated Resource Plan

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

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

Storm Damage Recovery

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

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

27

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

was $105 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

See Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information about the Kemper IGCC. The ultimate outcome of these tax matters cannot be determined at this time.

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 will apply primarily to the combined cycle and associated common facilities portion of the Kemper IGCC that were placed in service on August 9, 2014. The estimated cash flow benefit is approximately $100 million.

Investment Tax Credits

The IRS allocated $279 million (Phase II) of Internal Revenue Code Section 48A tax credits to Mississippi Power in connection with the Kemper IGCC. Through September 30, 2014, Southern Company had recorded tax benefits totaling $276.4 million for the Phase II credits, of which approximately $140 million have been utilized through that date. These credits will be amortized as a reduction to depreciation and amortization over the life of the Kemper IGCC and are dependent upon meeting the IRS certification requirements, including an in-service date no later than April 19, 2016 and the capture and sequestration (via enhanced oil recovery) of at least 65%of the CO₂ produced by the Kemper IGCC during operations in accordance with the Internal Revenue Code. 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.

Section 174 Research and Experimental Deduction

For the 2013 tax year, Southern Company included in its consolidated federal income tax return a deduction for research and experimental (R&E) expenditures related to the Kemper IGCC. Due to the uncertainty related to this tax position, Southern Company recorded an unrecognized tax benefit of approximately $100 million as of September 30, 2014. See Note (G) to the Condensed Financial Statements under "Unrecognized Tax Benefits" herein for additional information.

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 revised 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

28

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" and "Integrated Coal Gasification Combined Cycle" herein for additional information. For additional information about costs relating to Southern Power's acquisitions that involve construction of solar facilities, see Note (I) to the Condensed Financial Statements herein.

From 2013 through September 30, 2014, Southern Company has recorded pre-tax charges totaling $1.98 billion ($1.22 billion after tax) for revisions of estimated costs expected to be incurred on Mississippi Power's construction of the Kemper IGCC above the $2.88 billion cost cap established by the Mississippi PSC, net of the DOE Grants and excluding the Cost Cap Exceptions. In subsequent periods, any further changes in the estimated costs to complete construction of the Kemper IGCC subject to the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions, will be reflected in Southern Company's statements of income and these changes could be material.

Other Matters

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

TheultimateoutcomeofsuchpendingorpotentiallitigationagainstSouthernCompanyanditssubsidiariescannotbepredictedatthistime;however,forcurrentproceedingsnotspecificallyreportedinNote(B)totheCondensedFinancialStatementshereinorinNote3tothefinancialstatementsofSouthernCompanyinItem8ofthe Form 10-K,management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Southern Company's financial statements. See the Notes to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.

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

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

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Other Matters" of Southern Company in Item 7 of the Form 10-K for additional information regarding the court order for the DOE to set the spent fuel depositary fees at zero. On March 18, 2014, the U.S. Court of Appeals for the District of Columbia Circuit denied the DOE's request for rehearing of the November 2013 panel decision ordering that the DOE propose the nuclear waste fund fee be changed to zero. The DOE formally set the fee to zero effective May 16, 2014. On June 17, 2014, the Georgia PSC approved Georgia Power's request to credit customers the portion of fuel cost related to the nuclear waste fund fee. The nuclear waste fund rider became effective July 1, 2014. See "PSC Matters – Alabama Power – Nuclear Waste Fund Accounting Order" herein for information regarding an accounting order issued by the Alabama PSC which provides for continued recovery from customers of amounts associated with the permanent disposal of nuclear waste from the operation of Plant Farley. The ultimate outcome of this matter cannot be determined at this time.

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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

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

During 2014, Mississippi Power further extended the scheduled in-service date for the Kemper IGCC to the first half of 2016 and revised its cost estimate to complete construction and start-up of the Kemper IGCC to an amount that exceeds the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions. Mississippi Power does not intend to seek any rate recovery or any joint owner contributions for any related costs that exceed the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions.

As a result of the revisions to the cost estimate, Southern Company recorded total pre-tax charges to income for the estimated probable losses on the Kemper IGCC of $418.0 million ($258.1 million after tax) in the third quarter 2014, $380.0 million ($234.7 million after tax) in the first quarter 2014, $40.0 million ($24.7 million after tax) in the fourth quarter 2013, $150.0 million ($92.6 million after tax) in the third quarter 2013, $450.0 million ($277.9 million after tax) in the second quarter 2013, and $540.0 million ($333.5 million after tax) in the first quarter 2013. In the aggregate, Southern Company has incurred charges of $1.98 billion ($1.22 billion after tax) as a result of changes in the cost estimate for the Kemper IGCC through September 30, 2014.

Mississippi Power has experienced, and may continue to experience, material changes in the cost estimate for the Kemper IGCC. In subsequent periods, any further changes in the estimated costs to complete construction and start-up of the Kemper IGCC subject to the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions, will be reflected in Southern Company's statements of income and these changes could be material. Any further cost increases and/or extensions of the in-service date with respect to the Kemper IGCC may result from factors including, but not limited to, labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under construction or other agreements, operational performance, operational readiness, including specialized operator training, unforeseen engineering or design problems, start-up activities for this first-of-a-kind technology (including major equipment failure and system integration), and/or operations.

Mississippi Power's revised cost estimate includes costs through March 31, 2016. Any further extension of the in-service date is currently estimated to result in additional base costs of approximately $20 million to $30 million per month, which includes maintaining necessary levels of start-up labor, materials, and fuel, as well as operational resources required to execute start-up and commissioning activities.

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.

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Recently Issued Accounting Standards

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

FINANCIAL CONDITION AND LIQUIDITY

Overview

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Southern Company in Item 7 of the Form 10-K for additional information. Although earnings for the nine months ended September 30, 2014 were negatively affected by revisions to the cost estimate for the Kemper IGCC, Southern Company's financial condition remained stable at September 30, 2014. Through September 30, 2014, Southern Company has incurred non-recoverable cash expenditures of $1.18 billion and is expected to incur approximately $0.8 billion 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 $4.7 billion for the first nine months of 2014, an increase of $276 million from the corresponding period in 2013. The increase in net cash provided from operating activities was primarily due to an increase in revenue due to rate increases and the effects of weather and a reduction in fossil fuel stock resulting from an increase in KWH generation, partially offset by a decrease in receivables due to under recovered fuel costs. Net cash used for investing activities totaled $4.2 billion for the first nine months of 2014 primarily due to property additions to utility plant. Net cash provided from financing activities totaled $225 million for the first nine months of 2014. This was primarily due to issuances of long-term debt and common stock, partially offset by common stock dividend payments and a reduction in short-term debt. Fluctuations in cash flow from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes for the first nine months of 2014 include an increase of $2.0 billion in total property, plant, and equipment for construction of generation, transmission, and distribution facilities and an increase of $755 million in cash and cash equivalents. Other significant changes include a $1.2 billion increase in short-term and long-term debt to fund the Southern Company subsidiaries' continuous construction programs and general corporate purposes and an $849 million increase in total stockholders' equity.

At the end of the third quarter 2014, the market price of Southern Company's common stock was $43.65 per share (based on the closing price as reported on the New York Stock Exchange) and the book value was $22.07 per share, representing a market-to-book ratio of 198%, compared to $41.11, $21.43, and 192%, respectively, at the end of 2013. Southern Company's common stock dividend for the third quarter 2014 was $0.5250 per share compared to $0.5075 per share in the third quarter 2013.

Capital Requirements and Contractual Obligations

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Southern Company in Item 7 of the Form 10-K for a description of Southern Company's capital requirements for the construction programs of the Southern Company system, including estimated capital expenditures for new generating facilities and to comply with existing environmental statutes and regulations, scheduled maturities of long-term debt, as well as related interest, derivative obligations, preferred and preference stock dividends, leases, purchase commitments, trust funding requirements, and unrecognized tax benefits. Approximately $2.4 billion will be required through September 30, 2015 to fund maturities of long-term debt. See FUTURE EARNINGS POTENTIAL – "PSC Matters – Georgia Power –

31

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Renewables Development" herein for additional information regarding estimated purchased power contractual obligations.

The Southern Company system's construction program is currently estimated to be $7.2 billion for 2014, $5.8 billion for 2015, and $4.4 billion for 2016, which includes expenditures related to construction and start-up of the Kemper IGCC of $1.3 billion for 2014, $551 million for 2015, and $75 million for 2016 and expenditures related to Southern Power's acquisition of a solar facility of $508 million for 2014. 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 $569 million (including construction costs for all prior periods relating to its proposed ownership interest). The Southern Company system's amounts include capital expenditures related to contractual purchase commitments for nuclear fuel and capital expenditures covered under long-term service agreements.

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

The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing units, to meet regulatory requirements; changes in FERC rules and regulations; PSC approvals; changes in the expected environmental compliance program; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. Additionally, planned expenditures for plant acquisitions may vary due to market opportunities and Southern Power's ability to execute its growth strategy. See Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" and "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" and "Integrated Coal Gasification Combined Cycle" herein for information regarding additional factors that may impact construction expenditures.

Sources of Capital

Southern Company intends to meet its future capital needs through internal cash flow, short-term debt, and external security issuances. Equity capital can be provided from any combination of Southern Company's stock plans, private placements, or public offerings. The amount and timing of any additional equity capital to be raised in 2014, as well as in subsequent years, will be contingent on Southern Company's investment opportunities and the Southern Company system's capital requirements.

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

On February 20, 2014, Georgia Power and the DOE entered into a loan guarantee agreement (Loan Guarantee Agreement), pursuant to which the DOE agreed to guarantee borrowings to be made by Georgia Power under a multi-advance credit facility (FFB Credit Facility) among Georgia Power, the DOE, and the FFB. Georgia Power is 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 full recourse and also are secured by a first priority lien on (i) Georgia Power's 45.7% ownership interest in Plant Vogtle Units 3 and 4 (primarily the units under construction, the related real property, and any nuclear fuel loaded in the reactor core) and (ii) Georgia Power's rights and obligations under the principal contracts relating to Plant Vogtle Units 3 and 4. Under the FFB Credit

32

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Facility, Georgia Power may make term loan borrowings through the FFB. Proceeds of borrowings made under the FFB Credit Facility will be used to reimburse Georgia Power for a portion of certain costs of construction relating to Plant Vogtle Units 3 and 4 that are eligible for financing under the Loan Guarantee Agreement (Eligible Project Costs). Aggregate borrowings under the FFB Credit Facility may not exceed the lesser of (i) 70% of Eligible Project Costs or (ii) approximately $3.46 billion. See Note 6 to the financial statements of Southern Company in Item 8 of the Form 10-K for additional information regarding the Loan Guarantee Agreement and Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" herein for additional information regarding Plant Vogtle Units 3 and 4.

Eligible Project Costs incurred through September 30, 2014 would allow for borrowings of up to $2.0 billion under the FFB Credit Facility. Through September 30, 2014, Georgia Power has borrowed $1.0 billion under the FFB Credit Facility, leaving $1.0 billion of available borrowing ability.

Mississippi Power has received $245 million of DOE Grants that were used for the construction of the Kemper IGCC. An additional $25 million of DOE Grants is expected to be received for commercial operation of the Kemper IGCC. In addition, see Note (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 due to long-term debt that is due within one year, as well as cash needs, which can fluctuate significantly due to the seasonality of the business of the Southern Company system. To meet short-term cash needs and contingencies, Southern Company has substantial cash flow from operating activities and access to capital markets, including commercial paper programs which are backed by bank credit facilities.

At September 30, 2014, Southern Company and its subsidiaries had approximately $1.4 billion of cash and cash equivalents. Committed credit arrangements with banks at September 30, 2014 were as follows:

	Expires														Executable Term Loans				Due Within One Year
Company	2014		2015		2016		2017		2018		Total		Unused		One Year		Two Years		Term Out		No Term Out
	(in millions)										(in millions)				(in millions)				(in millions)
Southern Company	$	—	$	—	$	—	$	—	$	1,000	$	1,000	$	1,000	$	—	$	—	$	—	$	—
Alabama Power	70		158		50		—		1,030		1,308		1,308		58		—		58		170
Georgia Power	—		—		150		—		1,600		1,750		1,736		—		—		—		—
Gulf Power	20		60		165		30		—		275		275		50		—		50		30
Mississippi Power	15		120		165		—		—		300		300		25		40		65		70
Southern Power	—		—		—		—		500		500		499		—		—		—		—
Other	—		70		—		—		—		70		70		20		—		20		50
Total	$	105	$	408	$	530	$	30	$	4,130	$	5,203	$	5,188	$	153	$	40	$	193	$	320

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 September 30, 2014 was approximately $1.8 billion. In addition, at September 30, 2014, the traditional operating companies had $423 million of fixed rate pollution control revenue bonds that were required to be remarketed within the next 12 months.

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

33

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

Southern Company, the traditional operating companies, and Southern Power make short-term borrowings primarily through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above. Southern Company, the traditional operating companies, and Southern Power may also borrow through various other arrangements with banks. Commercial paper and short-term bank loans are included in notes payable in the balance sheets.

Details of short-term borrowings were as follows:

	Short-term Debt at September 30, 2014			Short-term Debt During the Period(a)
	Amount Outstanding		Weighted Average Interest Rate	Average Outstanding		Weighted Average Interest Rate	Maximum Amount Outstanding
	(in millions)			(in millions)			(in millions)
Commercial paper	$	361	0.3%	$	848	0.2%	$	1,528
Short-term bank debt	—		—	150		0.8%	250
Total	$	361	0.3%	$	998	0.3%

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

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

Credit Rating Risk

Southern Company and its subsidiaries do not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change of certain subsidiaries to BBB and Baa2, or BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel purchases, fuel transportation and storage, energy price risk management, and construction of new generation at Georgia Power's Plant Vogtle Units 3 and 4.

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

Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB and Baa2	$	9
At BBB- and/or Baa3	454
Below BBB- and/or Baa3	2,289

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.

34

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Financing Activities

During the first nine months of 2014, Southern Company issued approximately 7.8 million shares of common stock for approximately $295.5 million through the employee and director stock plans, of which 150,000 shares related to Southern Company's performance share plan.

Since August 2013, Southern Company has used shares held in treasury, to the extent available, to satisfy the requirements under the Southern Investment Plan and the employee savings plan and during the first nine months of 2014, issued approximately 5.0 million treasury shares for approximately $215.5 million. Beginning in June 2014, Southern Company used newly issued shares, as necessary, to satisfy the requirements.

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

Company	Senior Note Issuances		Senior Note Maturities		Revenue Bond Issuances and Remarketings of Purchased Bonds(a)		Revenue Bond Redemptions		Other Long-Term Debt Issuances			Other Long-Term Debt Redemptions(b)
	(in millions)
Southern Company	$	750	$	350	$	—	$	—	$	—		$	—
Alabama Power	400		—		—		—		—			—
Georgia Power	—		—		40		37		1,000			4
Gulf Power	200		—		42		29		—			—
Mississippi Power	—		—		—		—		493			222
Southern Power	—		—		—		—		10			1
Other	—		—		—		—		—			15
Elimination(c)	—		—		—		—		(220		)	(220		)
Total	$	1,350	$	350	$	82	$	66	$	1,283		$	22

(a) Includes remarketing by Gulf Power of $13 million aggregate principal amount of revenue bonds previously purchased and held by Gulf Power since December 2013 and remarketing by Georgia Power of $40 million aggregate principal amount of revenue bonds previously purchased and held by Georgia Power since 2010.

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

(c) Intercompany loan from Southern Company to Mississippi Power eliminated in Southern Company's Condensed Consolidated Financial Statements. This loan was repaid on September 29, 2014.

In August 2014, Southern Company issued $400 million aggregate principal amount of Series 2014A 1.30% Senior Notes due August 15, 2017 and $350 million aggregate principal amount of Series 2014B 2.15% Senior Notes due September 1, 2019. The proceeds were used to pay a portion of Southern Company's outstanding short-term indebtedness and for other general corporate purposes.

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 June 2014, Southern Company entered into a 90-day floating rate bank loan bearing interest based on one-month LIBOR. This short-term loan was for $250 million aggregate principal amount and the proceeds were used for working capital and other general corporate purposes, including the investment by Southern Company in its subsidiaries. This bank loan was repaid in August 2014.

In addition to the amounts reflected in the table above, in January 2014 and subsequent to September 30, 2014, Mississippi Power received an additional $75 million and $50 million, respectively, of interest-bearing refundable

35

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

deposits 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 2044 and the interest rate applicable to the remaining $500 million is 3.488% for an interest period that extends to 2029 and is expected to be reset from time to time thereafter through 2044. 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. In connection with its entry into the agreements with the DOE and the FFB, Georgia Power incurred issuance costs of approximately $66 million, which will be amortized over the life of the borrowings under the FFB Credit Facility.

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 September 30, 2014, Gulf Power's $75 million aggregate principal amount of Series K 4.90% Senior Notes was paid at maturity.

Subsequent to September 30, 2014, Alabama Power entered into forward-starting interest rate swaps to hedge exposure to interest rate changes related to an anticipated debt issuance. The notional amount of the swaps totaled $100 million.

Subsequent to September 30, 2014, Georgia Power entered into interest rate swaps to hedge exposure to interest rate changes related to existing debt. The notional amount of the swaps totaled $900 million.

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.

36

PART I

Item 3. Quantitative And Qualitative Disclosures About Market Risk.

During the nine months ended September 30, 2014, there were no material changes to each registrant's disclosures about market risk. For an in-depth discussion of each registrant's market risks, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of each registrant in Item 7 of the Form 10-K and Note 1 to the financial statements of each registrant under "Financial Instruments," Note 11 to the financial statements of Southern Company, Alabama Power, and Georgia Power, Note 10 to the financial statements of Gulf Power and Mississippi Power, and Note 9 to the financial statements of Southern Power in Item 8 of the Form 10-K. Also, see Note (H) to the Condensed Financial Statements herein for information relating to derivative instruments.

Item 4. Controls and Procedures.

(a) Evaluation of disclosure controls and procedures.

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

(b) Changes in internal controls.

There have been no changes in Southern Company's, Alabama Power's, Georgia Power's, Gulf Power's, Mississippi Power's, or Southern Power Company's internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) during the third 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.

37

ALABAMA POWER COMPANY

38

ALABAMA POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2014			2013			2014			2013
	(in millions)						(in millions)
Operating Revenues:
Retail revenues	$	1,512		$	1,438		$	4,058		$	3,800
Wholesale revenues, non-affiliates	72			66			222			186
Wholesale revenues, affiliates	31			47			168			163
Other revenues	54			53			166			155
Total operating revenues	1,669			1,604			4,614			4,304
Operating Expenses:
Fuel	442			467			1,288			1,240
Purchased power, non-affiliates	57			36			153			84
Purchased power, affiliates	54			30			140			102
Other operations and maintenance	334			316			989			965
Depreciation and amortization	174			170			521			487
Taxes other than income taxes	88			85			265			262
Total operating expenses	1,149			1,104			3,356			3,140
Operating Income	520			500			1,258			1,164
Other Income and (Expense):
Allowance for equity funds used during construction	15			7			36			23
Interest expense, net of amounts capitalized	(63		)	(65		)	(188		)	(196		)
Other income (expense), net	3			—			(5		)	1
Total other income and (expense)	(45		)	(58		)	(157		)	(172		)
Earnings Before Income Taxes	475			442			1,101			992
Income taxes	183			174			429			390
Net Income	292			268			672			602
Dividends on Preferred and Preference Stock	10			10			30			30
Net Income After Dividends on Preferred and Preference Stock	$	282		$	258		$	642		$	572

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2014		2013		2014		2013
	(in millions)				(in millions)
Net Income	$	292	$	268	$	672	$	602
Other comprehensive income (loss):
Qualifying hedges:
Reclassification adjustment for amounts included in net income, net of tax of $1, $1, $1 and $1, respectively	—		—		1		1
Total other comprehensive income (loss)	—		—		1		1
Comprehensive Income	$	292	$	268	$	673	$	603

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

39

ALABAMA POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Nine Months Ended September 30,
	2014			2013
	(in millions)
Operating Activities:
Net income	$	672		$	602
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	631			616
Deferred income taxes	68			200
Allowance for equity funds used during construction	(36		)	(23		)
Regulatory deferrals	(62		)	(14		)
Other, net	29			15
Changes in certain current assets and liabilities —
-Receivables	(139		)	(98		)
-Fossil fuel stock	106			173
-Materials and supplies	(8		)	16
-Other current assets	(32		)	(18		)
-Accounts payable	(64		)	(109		)
-Accrued taxes	210			105
-Accrued compensation	18			(36		)
-Retail fuel cost over recovery	2			42
-Other current liabilities	3			(2		)
Net cash provided from operating activities	1,398			1,469
Investing Activities:
Property additions	(966		)	(779		)
Nuclear decommissioning trust fund purchases	(178		)	(162		)
Nuclear decommissioning trust fund sales	178			162
Cost of removal, net of salvage	(50		)	(29		)
Change in construction payables	39			12
Other investing activities	(26		)	35
Net cash used for investing activities	(1,003		)	(761		)
Financing Activities:
Proceeds —
Senior note issuances	400			—
Capital contributions from parent company	20			18
Payment of preferred and preference stock dividends	(30		)	(30		)
Payment of common stock dividends	(412		)	(397		)
Other financing activities	(6		)	—
Net cash used for financing activities	(28		)	(409		)
Net Change in Cash and Cash Equivalents	367			299
Cash and Cash Equivalents at Beginning of Period	295			137
Cash and Cash Equivalents at End of Period	$	662		$	436
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $13 and $8 capitalized for 2014 and 2013, respectively)	$	174		$	182
Income taxes, net	227			154
Noncash transactions — accrued property additions at end of period	57			43

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

40

ALABAMA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Assets	At September 30, 2014			At December 31, 2013
	(in millions)
Current Assets:
Cash and cash equivalents	$	662		$	295
Receivables —
Customer accounts receivable	442			341
Unbilled revenues	133			142
Under recovered regulatory clause revenues	34			—
Other accounts and notes receivable	38			30
Affiliated companies	36			54
Accumulated provision for uncollectible accounts	(9		)	(8		)
Fossil fuel stock, at average cost	223			329
Materials and supplies, at average cost	397			375
Vacation pay	63			63
Prepaid expenses	83			57
Other regulatory assets, current	8			7
Other current assets	9			6
Total current assets	2,119			1,691
Property, Plant, and Equipment:
In service	22,688			22,092
Less accumulated provision for depreciation	8,430			8,114
Plant in service, net of depreciation	14,258			13,978
Nuclear fuel, at amortized cost	324			332
Construction work in progress	995			748
Total property, plant, and equipment	15,577			15,058
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	67			54
Nuclear decommissioning trusts, at fair value	738			714
Miscellaneous property and investments	83			80
Total other property and investments	888			848
Deferred Charges and Other Assets:
Deferred charges related to income taxes	528			519
Prepaid pension costs	290			276
Deferred under recovered regulatory clause revenues	46			25
Other regulatory assets, deferred	703			692
Other deferred charges and assets	142			142
Total deferred charges and other assets	1,709			1,654
Total Assets	$	20,293		$	19,251

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

41

ALABAMA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholder's Equity	At September 30, 2014			At December 31, 2013
	(in millions)
Current Liabilities:
Securities due within one year	$	54		$	—
Accounts payable —
Affiliated	245			198
Other	273			339
Customer deposits	86			85
Accrued taxes —
Accrued income taxes	146			11
Other accrued taxes	114			33
Accrued interest	62			61
Accrued vacation pay	53			53
Accrued compensation	98			74
Other regulatory liabilities, current	49			37
Other current liabilities	44			41
Total current liabilities	1,224			932
Long-term Debt	6,577			6,233
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	3,670			3,603
Deferred credits related to income taxes	72			75
Accumulated deferred investment tax credits	127			133
Employee benefit obligations	203			195
Asset retirement obligations	813			730
Other cost of removal obligations	864			828
Other regulatory liabilities, deferred	242			259
Deferred over recovered regulatory clause revenues	—			15
Other deferred credits and liabilities	54			61
Total deferred credits and other liabilities	6,045			5,899
Total Liabilities	13,846			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	2,292			2,262
Retained earnings	2,273			2,044
Accumulated other comprehensive loss	(25		)	(26		)
Total common stockholder's equity	5,762			5,502
Total Liabilities and Stockholder's Equity	$	20,293		$	19,251

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

42

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

THIRD QUARTER 2014 vs. THIRD QUARTER 2013

AND

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

OVERVIEW

Alabama Power operates as a vertically integrated utility providing electricity to retail and wholesale customers within its traditional service territory located within the State of Alabama in addition to wholesale customers in the Southeast.

Many factors affect the opportunities, challenges, and risks of Alabama Power's business of selling electricity. These factors include the ability to maintain a constructive regulatory environment, to maintain and grow energy sales given economic conditions, and to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand growth, increasingly stringent environmental standards, reliability, fuel, capital expenditures, and restoration following major storms. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Alabama Power for the foreseeable future.

Alabama Power continues to focus on several key performance indicators. These indicators include customer satisfaction, plant availability, system reliability, and net income after dividends on preferred and preference stock. For additional information on these indicators, see MANAGEMENT'S DISCUSSION AND ANALYSIS – OVERVIEW – "Key Performance Indicators" of Alabama Power in Item 7 of the Form 10-K.

RESULTS OF OPERATIONS

Net Income

Third Quarter 2014 vs. Third Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$24	9.3	$70	12.2

Alabama Power's net income after dividends on preferred and preference stock for the third quarter 2014 was $282 million compared to $258 million for the corresponding period in 2013. The increase in net income was related to an increase in revenue primarily due to warmer weather in the third quarter 2014 as compared to the corresponding period in 2013 and an increase in AFUDC equity, partially offset by increases in operating expenses.

Alabama Power's net income after dividends on preferred and preference stock for year-to-date 2014 was $642 million compared to $572 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 and warmer weather in the second and third quarters of 2014 as compared to the corresponding periods in 2013 and an increase in AFUDC equity, partially offset by increases in operating expenses.

Retail Revenues

Third Quarter 2014 vs. Third Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$74	5.1	$258	6.8

In the third quarter 2014, retail revenues were $1.51 billion compared to $1.44 billion for the corresponding period in 2013. For year-to-date 2014, retail revenues were $4.06 billion compared to $3.80 billion for the corresponding period in 2013.

43

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:

	Third Quarter 2014				Year-to-Date 2014
	(in millions)		(% change)		(in millions)		(% change)
Retail – prior year	$	1,438			$	3,800
Estimated change resulting from –
Rates and pricing	8		0.5		45		1.2
Sales growth	6		0.4		2		0.1
Weather	32		2.2		91		2.4
Fuel and other cost recovery	28		2.0		120		3.1
Retail – current year	$	1,512	5.1	%	$	4,058	6.8	%

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

Revenues attributable to changes in sales increased in the third quarter and year-to-date 2014 when compared to the corresponding periods in 2013. Industrial KWH energy sales increased 6.5% in the third quarter and 4.3% for year-to-date 2014 as a result of an increase in demand resulting from changes in production levels primarily in the primary metals, chemicals, forest products, automotive and plastics, and stone, clay, and glass sectors. Weather-adjusted residential KWH energy sales decreased 1.7% in the third quarter and 1.1% for year-to-date 2014 as a result of decreased customer usage. Weather-adjusted commercial KWH energy sales decreased 2.1% in the third quarter and 1.2% for year-to-date 2014 as a result of decreased customer usage. Household income, one of the primary drivers of residential customer usage, has been flat in 2014.

Revenues resulting from changes in weather increased in the third quarter 2014 due to warmer weather experienced in Alabama Power's service territory compared to the corresponding period in 2013. For the third quarter 2014, the resulting increases were 3.8% and 1.9% for residential and commercial sales revenue, respectively.

Revenues resulting from changes in weather increased year-to-date 2014 primarily due to colder weather experienced in Alabama Power's service territory in the first quarter 2014 and warmer weather in the second and third quarters 2014 when compared to the corresponding periods in 2013. For year-to-date 2014, the resulting increases were 4.1% and 2.2% for residential and commercial sales revenue, respectively.

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

Wholesale Revenues – Non-Affiliates

Third Quarter 2014 vs. Third Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$6	9.1	$36	19.4

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

44

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income.

In the third quarter 2014, wholesale revenues from sales to non-affiliates were $72 million compared to $66 million for the corresponding period in 2013. The increase was primarily due to an 11.2% increase in KWH sales primarily due to the availability of Alabama Power's lower cost generation partially offset by a 2.3% decrease in the price of energy primarily due to the lower cost of coal.

For year-to-date 2014, wholesale revenues from sales to non-affiliates were $222 million compared to $186 million for the corresponding period in 2013. The increase was primarily due to a 16.4% increase in KWH sales primarily due to the availability of Alabama Power's lower cost generation and an increase of 2.2% in the price of energy primarily due to higher natural gas prices during the winter months of 2014.

Wholesale Revenues – Affiliates

Third Quarter 2014 vs. Third Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$(16)	(34.0)	$5	3.1

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

In the third quarter 2014, wholesale revenues from sales to affiliates were $31 million compared to $47 million for the corresponding period in 2013. The decrease was primarily due to a 38.8% decrease in KWH sales primarily due to decreased availability of hydro generation due to less rainfall in the third quarter 2014 as compared to the corresponding period in 2013 as well as the addition of new generation in the Southern Company system. This decrease was partially offset by a 4.1% increase in the price of energy primarily due to higher natural gas prices.

Other Revenues

Third Quarter 2014 vs. Third Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$1	1.9	$11	7.1

For year-to-date 2014, other revenues were $166 million compared to $155 million for the corresponding period in 2013. The increase was primarily due to increases in co-generation steam revenues, open access transmission tariff revenues, and transmission service agreement revenues.

Fuel and Purchased Power Expenses

	Third Quarter 2014 vs. Third Quarter 2013				Year-to-Date 2014 vs. Year-to-Date 2013
	(change in millions)			(% change)	(change in millions)		(% change)
Fuel	$	(25	)	(5.4)	$	48	3.9
Purchased power – non-affiliates	21			58.3	69		82.1
Purchased power – affiliates	24			80.0	38		37.3
Total fuel and purchased power expenses	$	20			$	155

In the third quarter 2014, total fuel and purchased power expenses were $553 million compared to $533 million for the corresponding period in 2013. The increase was primarily due to a $42 million increase in the volume of KWHs

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ALABAMA POWER COMPANY

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

purchased, a $6 million increase related to the volume of KWHs generated, and a $3 million increase in the average cost of purchased power, partially offset by a $31 million decrease in the average cost of fuel.

For year-to-date 2014, total fuel and purchased power expenses were $1.58 billion compared to $1.43 billion for the corresponding period in 2013. The increase was primarily due to a $65 million increase related to the volume of KWHs purchased, a $48 million increase in the volume of KWHs generated, and a $42 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" of Alabama Power in Item 7 of the Form 10-K for additional information.

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

	Third Quarter 2014	Third Quarter 2013	Year-to-Date 2014	Year-to-Date 2013
Total generation (billions of KWHs)	17	18	50	49
Total purchased power (billions of KWHs)	2	1	5	3
Sources of generation (percent) —
Coal	59	57	55	53
Nuclear	23	21	23	22
Gas	16	16	16	16
Hydro	2	6	6	9
Cost of fuel, generated (cents per net KWH) —
Coal	3.04	3.41	3.24	3.37
Nuclear	0.81	0.84	0.84	0.83
Gas	3.54	3.27	3.83	3.38
Average cost of fuel, generated (cents per net KWH)(a)	2.61	2.80	2.75	2.76
Average cost of purchased power (cents per net KWH)(b)	6.56	6.44	6.32	5.44

(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 third quarter 2014, fuel expense was $442 million compared to $467 million for the corresponding period in 2013. The decrease was primarily due to a 10.8% decrease in the average cost of coal generation. This was partially offset by a 66.7% decrease in the volume of KWHs generated by hydro facilities as a result of less rainfall and an 8.3% increase in the average cost of natural gas per KWH generated, which excludes fuel associated with tolling agreements.

For year-to-date 2014, fuel expense was $1.29 billion compared to $1.24 billion for the corresponding period in 2013. The increase was primarily due to a 32.9% decrease in the volume of KWHs generated by hydro facilities as a result of less rainfall, a 13.3% increase in the average cost of natural gas per KWH generated, which excludes fuel associated with tolling agreements, a 6.9% increase in KWHs generated by nuclear fuel due to an outage in the second quarter 2013, and a 5.3% increase in the volume of KWHs generated by coal.

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ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Purchased Power – Non-Affiliates

In the third quarter 2014, purchased power expense from non-affiliates was $57 million compared to $36 million for the corresponding period in 2013. The increase was related to a 48.3% increase in the average cost per KWH purchased and a 3.4% increase in the amount of energy purchased due to the addition of a new PPA in 2014.

For year-to-date 2014, purchased power expense from non-affiliates was $153 million compared to $84 million for the corresponding period in 2013. The increase was related to a 65.9% increase in the average cost per KWH purchased primarily due to demand during peak periods and the addition of a new PPA in 2014 and a 7.2% 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 third quarter 2014, purchased power expense from affiliates was $54 million compared to $30 million for the corresponding period in 2013. The increase was related to a 130.0% increase in the amount of energy purchased primarily due to the decreased availability of hydro generation due to less rainfall during the third quarter 2014 compared to the corresponding period in 2013 as well as the addition of new capacity in the Southern Company system during the third quarter 2014. This increase was partially offset by a 23.6% decrease in the average cost per KWH purchased due to availability of lower cost Southern Company system generation at the time of purchase.

For year-to-date 2014, purchased power expense from affiliates was $140 million compared to $102 million for the corresponding period in 2013. The increase was related to a 63.1% 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 partially offset by a 16.5% decrease in the average cost per KWH purchased due to the availability of lower cost Southern Company system generation at the time of purchase.

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

Other Operations and Maintenance Expenses

Third Quarter 2014 vs. Third Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$18	5.7	$24	2.5

In the third quarter 2014, other operations and maintenance expenses were $334 million compared to $316 million for the corresponding period in 2013. For year-to-date 2014, other operations and maintenance expenses were $989 million compared to $965 million for the corresponding period in 2013. The increases were primarily due to increases in labor and contract labor costs. These increases were partially offset by the implementation of an accounting order in 2014 allowing deferral of non-nuclear outage costs. Alabama Power deferred approximately $16 million and $57 million of non-nuclear outage expenditures in the third quarter and year-to-date 2014, respectively. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Non-Nuclear Outage Accounting Order" of Alabama Power in Item 7 of the Form 10-K for additional information.

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ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Depreciation and Amortization

Third Quarter 2014 vs. Third Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$4	2.4	$34	7.0

For year-to-date 2014, depreciation and amortization was $521 million compared to $487 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" of Alabama Power in Item 7 of the Form 10-K for additional information regarding Alabama Power's revision to Rate CNP Environmental. See also MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Compliance and Pension Cost Accounting Order" of Alabama Power in Item 7 of the Form 10-K for additional information regarding Alabama Power's deferral of costs under this accounting order.

Allowance for Equity Funds Used During Construction

Third Quarter 2014 vs. Third Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$8	114.3	$13	56.5

In the third quarter 2014, AFUDC equity was $15 million compared to $7 million for the corresponding period in 2013. For year-to-date 2014, AFUDC equity was $36 million compared to $23 million for the corresponding period in 2013. The increases were primarily due to additional capital expenditures for steam environmental and steam generation. Also contributing to the third quarter increase was an increase in capital expenditures for nuclear fuel.

Income Taxes

Third Quarter 2014 vs. Third Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$9	5.2	$39	10.0

In the third quarter 2014, income taxes were $183 million compared to $174 million for the corresponding period in 2013. For year-to-date 2014, income taxes were $429 million compared to $390 million for the corresponding period in 2013. The increases were 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 and growing sales which is subject to a number of factors. These factors include weather, competition, new energy contracts with other utilities, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in Alabama Power's service territory. Changes in regional and global economic conditions may impact sales for Alabama Power as the pace of the economic recovery remains uncertain. The timing and extent of the economic recovery will impact growth and may impact future earnings. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Alabama Power in Item 7 of the Form 10-K.

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ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Environmental Matters

Compliance costs related to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively affect results of operations, cash flows, and financial condition. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under "Environmental Matters" in Item 8 of the Form 10-K for additional information.

Environmental Statutes and Regulations

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

Air Quality

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

On April 29, 2014, the U.S. Supreme Court overturned the U.S. Court of Appeals for the District of Columbia Circuit's August 2012 decision to vacate CSAPR and remanded the case back to the U.S. Court of Appeals for the District of Columbia Circuit for further proceedings. On October 23, 2014, the U.S. Court of Appeals for the District of Columbia Circuit granted the EPA's motion to lift the stay on CSAPR implementation and approved a revised schedule under which the first phase of the rule will go into effect beginning January 1, 2015. The Southern Company system has developed and continually updates a comprehensive environmental compliance strategy to assess compliance obligations associated with current and proposed environmental requirements, including CSAPR. The ultimate financial and unit operational impact of the rule cannot be determined at this time and is dependent on the outcome of further legal proceedings, the manner in which the EPA and the states implement the final rule, and the development of related emissions allowance markets.

On September 17, 2014, the EPA published a supplemental proposal for the SSM rule. The EPA previously entered into a revised settlement agreement requiring the EPA to finalize the proposed rules by May 22, 2015. The proposed rule would require states subject to the rule, including Alabama, to revise their SSM provisions within 18 months after issuance of the final rule. The ultimate impact of the proposed SSM rule will depend on the specific provisions of the final rule, the development and implementation of rules at the state level, and the outcome of any legal challenges and cannot be determined at this time.

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

Water Quality

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

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ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

impact of the proposed rule will depend on the specific requirements of the final rule and the outcome of any legal challenges and cannot be determined at this time.

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

On August 15, 2014, the EPA published a final rule establishing standards for reducing effects on fish and other aquatic life caused by new and existing cooling water intake structures at existing power plants and manufacturing facilities, which became effective October 14, 2014. The ultimate outcome of this final rule will depend on the results of additional studies and implementation of the rule by state regulators, but could result in additional capital and operational costs associated with changes to existing intake structures and cooling systems and increased costs associated with the construction of new generating units. The ultimate impact of this rule will depend on the outcome of any legal challenges and cannot be determined at this time.

Global Climate Issues

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

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

On October 28, 2014, the EPA issued a notice of data availability related to the proposed Clean Power Plan, which was not intended to revise the EPA's proposal but to provide the public with an opportunity to consider and comment on technical issues and data related to the guidelines. The Southern Company system expects to file comments with the EPA at or prior to the EPA's December 1, 2014 extended deadline. These comments may include a preliminary estimated cost of complying with the proposed guidelines utilizing one of the EPA's compliance scenarios. These costs could be significant to the utility industry and the Southern Company system. However, the ultimate financial and operational impact of the Clean Power Plan proposed guidelines on the Southern Company system cannot be determined at this time and will be dependent upon numerous factors. These factors include: the structure, timing, and content of the EPA's final guidelines; individual state implementation of these guidelines, including the potential that state implementation plans impose different standards; additional rulemaking activities in response to legal challenges and court decisions; the impact of future changes in generation and emissions-related technology and costs; the impact of future decisions regarding unit retirement and replacement, including the type and amount of any such replacement capacity; and the time periods over which compliance will be required.

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

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ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

FERC Matters

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters" of Alabama Power in Item 7 of the Form 10-K for additional information on Alabama Power's relicensing applications for the hydroelectric developments on the Coosa River and the Warrior River. On September 26, 2014, the U.S. Court of Appeals for the District of Columbia Circuit dismissed the appeal of the Smith Lake Improvement and Stakeholders' Association from the FERC's orders related to the Warrior River relicensing proceedings for lack of jurisdiction. The ultimate outcome of this matter cannot be determined at this time.

PSC Matters

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters" of Alabama Power in Item 7 of the Form 10-K for additional information regarding Alabama Power's recovery of retail costs through various regulatory clauses and accounting orders. The recovery balance of each regulatory clause for Alabama Power is reported in Note (B) to the Condensed Financial Statements herein.

Environmental Accounting Order

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

As part of its environmental compliance strategy, Alabama Power plans to retire Plant Gorgas Units 6 and 7. These units represent 200 MWs of Alabama Power's approximately 12,200 MWs of generating capacity. Alabama Power also plans to cease using coal at Plant Barry Units 1 and 2 (250 MWs), but such units will remain available on a limited basis with natural gas as the fuel source. Additionally, Alabama Power expects to cease using coal at Plant Barry Unit 3 (225 MWs) and Plant Greene County Units 1 and 2 (300 MWs) and begin operating those units solely on natural gas. These plans are expected to be effective no later than April 2016.

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

Nuclear Waste Fund Accounting Order

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

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

Cost of Removal Accounting Order

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters" of Alabama Power in Item 7 of the Form 10-K regarding the previously approved compliance and pension costs accounting order and non-nuclear outage accounting order.

51

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

On November 3, 2014, the Alabama PSC issued an accounting order authorizing Alabama Power to fully amortize the balances in certain regulatory asset accounts, projected to be $120 million at December 31, 2014. This amortization expense will be offset by the amortization of up to $120 million of the regulatory liability for other cost of removal obligations. The regulatory asset account balances to be fully amortized as of December 31, 2014 represent costs deferred under the compliance and pension cost accounting order as well as the non-nuclear outage accounting order, which were approved by the Alabama PSC in November 2012 and August 2013, respectively. This accounting order also requires Alabama Power to terminate, as of December 31, 2014, the regulatory asset accounts created pursuant to the compliance and pension cost accounting order and the non-nuclear outage accounting order. Consequently, Alabama Power will not defer any expenditures in 2015, 2016, and 2017 related to critical electric infrastructure and domestic nuclear facilities under these orders.

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. The DOE formally set the fee to zero effective May 16, 2014. See "PSC Matters – Nuclear Waste Fund Accounting Order" herein for information regarding an accounting order issued by the Alabama PSC which provides for continued recovery from customers of amounts associated with the permanent disposal of nuclear waste from the operation of Plant Farley.The ultimate outcome of this matter cannot be determined at this time.

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ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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

Recently Issued Accounting Standards

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

FINANCIAL CONDITION AND LIQUIDITY

Overview

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

Net cash provided from operating activities totaled $1.4 billion for the first nine months of 2014, a decrease of $71 million as compared to the first nine months of 2013. The decrease in net cash provided from operating activities was primarily due to an increase in income tax payments and changes in the timing of fossil fuel stock purchases as compared to the first nine months of 2013. Net cash used for investing activities totaled $1.0 billion for the first nine months of 2014 primarily due to gross property additions related to distribution, environmental, transmission, and steam generation. Net cash used for financing activities totaled $28 million for the first nine months of 2014 primarily due to the payment of common and preferred stock dividends, partially offset by the issuance of long-term debt. Fluctuations in cash flow from financing activities vary period to period based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes for the first nine months of 2014 include an increase of $519 million in property, plant, and equipment, primarily due to additions to distribution, environmental, transmission, and steam generation, $367 million in cash and cash equivalents, $344 million in long-term debt primarily due to the issuance of additional senior notes, and $135 million in accrued income taxes.

Capital Requirements and Contractual Obligations

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Alabama Power in Item 7 of the Form 10-K for a description of Alabama Power's capital requirements for its construction program, including estimated capital expenditures to comply with existing environmental statutes and regulations, scheduled maturities of long-term debt, as well as the related interest, derivative obligations, preferred and preference stock dividends, leases, purchase commitments, and trust funding requirements. Approximately $54 million will be required through September 30, 2015 to fund maturities of long-term debt.

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ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

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

Sources of Capital

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

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

At September 30, 2014, Alabama Power had approximately $662 million of cash and cash equivalents. Committed credit arrangements with banks at September 30, 2014 were as follows:

Expires(a)												Executable Term Loans				Due Within One Year
2014		2015		2016		2018		Total		Unused		One Year		Two Years		Term Out		No Term Out
(in millions)								(in millions)				(in millions)				(in millions)
$	70	$	158	$	50	$	1,030	$	1,308	$	1,308	$	58	$	—	$	58	$	170

(a) No credit arrangements expire in 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 September 30, 2014, Alabama Power had $784 million of outstanding variable rate pollution control revenue bonds requiring liquidity support. In addition, at September 30, 2014, Alabama Power

54

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

had $280 million of fixed rate pollution control revenue bonds that will be required to be remarketed within the next 12 months.

Alabama Power may meet short-term cash needs through its commercial paper program. Alabama Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Alabama Power and the other traditional operating companies. Proceeds from such issuances for the benefit of Alabama Power are loaned directly to Alabama Power. The obligations of each company under these arrangements are several and there is no cross-affiliate credit support.

Details of short-term borrowings were as follows:

	Short-term Debt at September 30, 2014			Short-term Debt During the Period(a)
	Amount Outstanding		Weighted Average Interest Rate	Average Outstanding		Weighted Average Interest Rate	Maximum Amount Outstanding
	(in millions)			(in millions)			(in millions)
Commercial Paper	$	—	—%	$	27	0.1%	$	300

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

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

Credit Rating Risk

Alabama Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to below BBB- and/or Baa3. These contracts are primarily for physical electricity purchases, fuel purchases, fuel transportation and storage, and energy price risk management. At September 30, 2014, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $343 million. Included in these amounts are certain agreements that could require collateral in the event that one or more Southern Company system power pool participants has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, any credit rating downgrade could impact Alabama Power's ability to access capital markets, particularly the short-term debt market and the variable rate pollution control revenue bond market.

Financing Activities

In August 2014, Alabama Power issued $400 million aggregate principal amount of Series 2014A 4.150% Senior Notes due August 15, 2044. The proceeds were used for general corporate purposes, including Alabama Power's continuous construction program.

Subsequent to September 30, 2014, Alabama Power entered into forward-starting interest rate swaps to hedge exposure to interest rate changes related to an anticipated debt issuance. The notional amount of the swaps totaled $100 million.

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

55

GEORGIA POWER COMPANY

56

GEORGIA POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2014			2013			2014			2013
	(in millions)						(in millions)
Operating Revenues:
Retail revenues	$	2,452		$	2,314		$	6,502		$	5,922
Wholesale revenues, non-affiliates	80			77			269			212
Wholesale revenues, affiliates	7			3			38			14
Other revenues	92			90			277			260
Total operating revenues	2,631			2,484			7,086			6,408
Operating Expenses:
Fuel	684			691			2,055			1,767
Purchased power, non-affiliates	77			64			219			175
Purchased power, affiliates	172			152			522			503
Other operations and maintenance	456			402			1,334			1,230
Depreciation and amortization	211			201			628			605
Taxes other than income taxes	111			102			320			292
Total operating expenses	1,711			1,612			5,078			4,572
Operating Income	920			872			2,008			1,836
Other Income and (Expense):
Allowance for equity funds used during construction	13			11			29			24
Interest expense, net of amounts capitalized	(88		)	(92		)	(262		)	(279		)
Other income (expense), net	1			(1		)	—			(2		)
Total other income and (expense)	(74		)	(82		)	(233		)	(257		)
Earnings Before Income Taxes	846			790			1,775			1,579
Income taxes	317			299			660			600
Net Income	529			491			1,115			979
Dividends on Preferred and Preference Stock	4			4			13			13
Net Income After Dividends on Preferred and Preference Stock	$	525		$	487		$	1,102		$	966

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2014		2013		2014		2013
	(in millions)				(in millions)
Net Income	$	529	$	491	$	1,115	$	979
Other comprehensive income (loss):
Qualifying hedges:
Reclassification adjustment for amounts included in net income, net of tax of $1, $-, $1 and $1, respectively	—		1		1		2
Total other comprehensive income (loss)	—		1		1		2
Comprehensive Income	$	529	$	492	$	1,116	$	981

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

57

GEORGIA POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Nine Months Ended September 30,
	2014			2013
	(in millions)
Operating Activities:
Net income	$	1,115		$	979
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	757			734
Deferred income taxes	121			354
Allowance for equity funds used during construction	(29		)	(24		)
Retail fuel cost over recovery — long-term	(44		)	(123		)
Deferred expenses	(35		)	(34		)
Pension, postretirement, and other employee benefits	28			58
Other, net	23			28
Changes in certain current assets and liabilities —
-Receivables	(377		)	(191		)
-Fossil fuel stock	337			213
-Prepaid income taxes	19			11
-Other current assets	(24		)	38
-Accrued taxes	148			131
-Other current liabilities	29			(46		)
Net cash provided from operating activities	2,068			2,128
Investing Activities:
Property additions	(1,364		)	(1,165		)
Investment of restricted cash	—			(89		)
Distribution of restricted cash	—			89
Nuclear decommissioning trust fund purchases	(457		)	(582		)
Nuclear decommissioning trust fund sales	455			580
Cost of removal, net of salvage	(39		)	(42		)
Change in construction payables, net of joint owner portion	16			(28		)
Prepaid long-term service agreements	(66		)	(14		)
Other investing activities	(3		)	—
Net cash used for investing activities	(1,458		)	(1,251		)
Financing Activities:
Increase (decrease) in notes payable, net	(836		)	211
Proceeds —
Capital contributions from parent company	39			30
Pollution control revenue bonds issuances	40			89
Senior notes issuances	—			850
FFB loan	1,000			—
Redemptions —
Pollution control revenue bonds	(37		)	(89		)
Senior notes	—			(1,250		)
Payment of preferred and preference stock dividends	(13		)	(13		)
Payment of common stock dividends	(715		)	(680		)
FFB loan issuance costs	(49		)	(2		)
Other financing activities	(6		)	(15		)
Net cash used for financing activities	(577		)	(869		)
Net Change in Cash and Cash Equivalents	33			8
Cash and Cash Equivalents at Beginning of Period	30			45
Cash and Cash Equivalents at End of Period	$	63		$	53
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $13 and $10 capitalized for 2014 and 2013, respectively)	$	235		$	247
Income taxes, net	309			109
Noncash transactions — accrued property additions at end of period	220			230

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

58

GEORGIA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Assets	At September 30, 2014			At December 31, 2013
	(in millions)
Current Assets:
Cash and cash equivalents	$	63		$	30
Receivables —
Customer accounts receivable	738			512
Unbilled revenues	241			209
Joint owner accounts receivable	75			67
Other accounts and notes receivable	54			117
Affiliated companies	21			21
Accumulated provision for uncollectible accounts	(8		)	(5		)
Fossil fuel stock, at average cost	405			742
Materials and supplies, at average cost	431			409
Vacation pay	88			88
Prepaid income taxes	57			97
Other regulatory assets, current	62			66
Other current assets	118			54
Total current assets	2,345			2,407
Property, Plant, and Equipment:
In service	30,818			30,132
Less accumulated provision for depreciation	11,192			10,970
Plant in service, net of depreciation	19,626			19,162
Other utility plant, net	218			240
Nuclear fuel, at amortized cost	516			523
Construction work in progress	3,884			3,500
Total property, plant, and equipment	24,244			23,425
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	58			46
Nuclear decommissioning trusts, at fair value	772			751
Miscellaneous property and investments	37			44
Total other property and investments	867			841
Deferred Charges and Other Assets:
Deferred charges related to income taxes	701			718
Prepaid pension costs	133			118
Deferred under recovered regulatory clause revenues	175			—
Other regulatory assets, deferred	1,156			1,152
Other deferred charges and assets	294			246
Total deferred charges and other assets	2,459			2,234
Total Assets	$	29,915		$	28,907

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

59

GEORGIA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholder's Equity	At September 30, 2014			At December 31, 2013
	(in millions)
Current Liabilities:
Securities due within one year	$	503		$	5
Notes payable	211			1,047
Accounts payable —
Affiliated	503			417
Other	476			472
Customer deposits	250			246
Accrued taxes —
Accrued income taxes	155			—
Other accrued taxes	313			321
Accrued interest	99			91
Accrued vacation pay	60			61
Accrued compensation	111			80
Other current liabilities	177			166
Total current liabilities	2,858			2,906
Long-term Debt	9,135			8,633
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	5,295			5,200
Deferred credits related to income taxes	107			112
Accumulated deferred investment tax credits	196			203
Employee benefit obligations	580			542
Asset retirement obligations	1,215			1,210
Other cost of removal obligations	58			43
Other deferred credits and liabilities	178			201
Total deferred credits and other liabilities	7,629			7,511
Total Liabilities	19,622			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	5,683			5,633
Retained earnings	3,950			3,565
Accumulated other comprehensive loss	(4		)	(5		)
Total common stockholder's equity	10,027			9,591
Total Liabilities and Stockholder's Equity	$	29,915		$	28,907

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

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GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

THIRD QUARTER 2014 vs. THIRD QUARTER 2013

AND

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

OVERVIEW

Georgia Power operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located within the State of Georgia and to wholesale customers in the Southeast.

Many factors affect the opportunities, challenges, and risks of Georgia Power's business of selling electricity. These factors include the ability to maintain a constructive regulatory environment, to maintain and grow energy sales given economic conditions, and to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand growth, increasingly stringent environmental standards, reliability, and fuel. In addition, Georgia Power is currently constructing Plant Vogtle Units 3 and 4 to increase its generation diversity and meet future supply needs. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Georgia Power for the foreseeable future.

Georgia Power continues to focus on several key performance indicators. These indicators include customer satisfaction, plant availability, system reliability, the execution of major construction projects, and net income after dividends on preferred and preference stock. For additional information on these indicators, see MANAGEMENT'S DISCUSSION AND ANALYSIS – OVERVIEW – "Key Performance Indicators" of Georgia Power in Item 7 of the Form 10-K.

RESULTS OF OPERATIONS

Net Income

Third Quarter 2014 vs. Third Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$38	7.8	$136	14.1

Georgia Power's net income after dividends on preferred and preference stock for the third quarter 2014 was $525 million compared to $487 million for the corresponding period in 2013. The increase was primarily due to an increase in retail base revenues effective January 1, 2014 as authorized under the 2013 ARP and warmer weather in the third quarter 2014 as compared to the corresponding period in 2013, partially offset by higher non-fuel operations and maintenance expenses.

Georgia Power's net income after dividends on preferred and preference stock for year-to-date 2014 was $1.10 billion compared to $966 million for the corresponding period in 2013. The increase was primarily due to colder weather in the first quarter 2014 and warmer weather in the second and third quarters 2014 as compared to the corresponding periods in 2013 and an increase in retail base revenues effective January 1, 2014 as authorized under the 2013 ARP, partially offset by higher non-fuel operations and maintenance expenses.

Retail Revenues

Third Quarter 2014 vs. Third Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$138	6.0	$580	9.8

In the third quarter 2014, retail revenues were $2.45 billion compared to $2.31 billion for the corresponding period in 2013. For year-to-date 2014, retail revenues were $6.50 billion compared to $5.92 billion for the corresponding period in 2013.

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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:

	Third Quarter 2014				Year-to-Date  2014
	(in millions)		(% change)		(in millions)		(% change)
Retail – prior year	$	2,314			$	5,922
Estimated change resulting from –
Rates and pricing	67		2.9		147		2.5
Sales growth	1		0.1		23		0.4
Weather	51		2.2		131		2.2
Fuel cost recovery	19		0.8		279		4.7
Retail – current year	$	2,452	6.0	%	$	6,502	9.8	%

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

Revenues attributable to changes in sales increased in the third quarter and year-to-date 2014 when compared to the corresponding periods in 2013. Weather-adjusted residential KWH sales decreased 0.1%, weather-adjusted commercial KWH sales decreased 1.1%, and weather-adjusted industrial KWH sales increased 2.4% in the third quarter 2014 when compared to the corresponding period in 2013. For year-to-date 2014, weather-adjusted residential KWH sales increased 0.8%, weather-adjusted commercial KWH sales decreased 0.2%, and weather-adjusted industrial KWH sales increased 1.7% when compared to the corresponding period in 2013. Increased demand in the primary metals, non-manufacturing, paper, and transportation sectors was the main contributor to the increase in weather-adjusted industrial sales. Decreased customer usage contributed to the decrease in weather-adjusted commercial sales. An increase of approximately 20,000 residential customers since September 30, 2013 contributed to the year-to-date 2014 increase in weather-adjusted residential KWH sales, partially offset by decreased customer usage. Household income, one of the primary drivers of residential customer usage, has been flat in 2014.

Fuel revenues and costs are allocated between retail and wholesale jurisdictions. Retail fuel cost recovery revenues increased $19 million and $279 million in the third quarter and year-to-date 2014, respectively, when compared to the corresponding periods in 2013 primarily due to higher natural gas costs and higher energy sales resulting from colder weather in the first quarter 2014 and warmer weather in the second and third quarters 2014 as compared to the corresponding periods in 2013. 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

Third Quarter 2014 vs. Third Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$3	3.9	$57	26.9

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

62

GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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.

For year-to-date 2014, wholesale revenues from sales to non-affiliates were $269 million compared to $212 million for the corresponding period in 2013 due to increased demand resulting from colder weather in the first quarter 2014 and warmer weather in the second and third quarters 2014 as compared to the corresponding periods in 2013 and the lower cost of Georgia Power-owned generation compared to the market cost of available energy.

Wholesale Revenues – Affiliates

Third Quarter 2014 vs. Third Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$4	N/M	$24	171.4

N/M – Not meaningful

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.

For year-to-date 2014, wholesale revenues from sales to affiliates were $38 million compared to $14 million for the corresponding period in 2013. The increase was due to higher demand resulting from colder weather in the first quarter 2014 and warmer weather in the second and third quarters 2014 as compared to the corresponding periods in 2013 and the lower cost of Georgia Power-owned generation.

Other Revenues

Third Quarter 2014 vs. Third Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$2	2.2	$17	6.5

For year-to-date 2014, other operating revenues were $277 million compared to $260 million in the corresponding period in 2013. The increase was primarily due to an increase of $13 million in open access transmission tariff revenues and $6 million of solar application fee revenue for year-to-date 2014 as compared to the corresponding period in 2013.

Fuel and Purchased Power Expenses

	Third Quarter 2014 vs. Third Quarter 2013					Year-to-Date 2014 vs. Year-to-Date 2013
	(change in millions)			(% change)		(change in millions)		(% change)
Fuel	$	(7	)	(1.0	)	$	288	16.3
Purchased power – non-affiliates	13			20.3		44		25.1
Purchased power – affiliates	20			13.2		19		3.8
Total fuel and purchased power expenses	$	26				$	351

In the third quarter 2014, total fuel and purchased power expenses were $933 million compared to $907 million in the corresponding period in 2013. The increase in the third quarter 2014 was primarily due to an $82 million increase in the volume of KWHs generated and purchased as a result of warmer weather in the third quarter 2014 as

63

GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

compared to the corresponding period in 2013 driving higher customer demand, partially offset by a $56 million decrease in the average cost of fuel primarily due to lower coal prices.

For year-to-date 2014, total fuel and purchased power expenseswere $2.80 billion compared to $2.45 billion in the corresponding period in 2013.The increase in year-to-date 2014 was primarily due to a $66 million increase in the average cost of fuel and purchased power primarily due to higher natural gas prices and a $285 million increase in the volume of KWHs generated primarily as a result of colder weather in the first quarter 2014 and warmer weather in the second and third quarters 2014 as compared to the corresponding periods in 2013 driving higher customer demand.

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

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

	Third Quarter 2014	Third Quarter 2013	Year-to-Date 2014	Year-to-Date 2013
Total generation (billions of KWHs)	19	19	55	50
Total purchased power (billions of KWHs)	6	5	16	17
Sources of generation (percent) —
Coal	45	42	45	35
Nuclear	20	22	21	23
Gas	34	34	32	39
Hydro	1	2	2	3
Cost of fuel, generated (cents per net KWH) —
Coal	4.19	4.89	4.49	4.99
Nuclear	0.86	0.91	0.90	0.91
Gas	3.41	3.34	3.84	3.34
Average cost of fuel, generated (cents per net KWH)	3.25	3.47	3.51	3.37
Average cost of purchased power (cents per net KWH)(a)	5.03	5.00	5.42	4.80

(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 third quarter 2014, fuel expense was $684 million compared to $691 million in the corresponding period in 2013. The decrease was primarily due to a 14.3% decrease in the average cost of coal per KWH generated, partially offset by a 1.5% increase in the volume of KWHs generated as a result of warmer weather in the third quarter 2014 as compared to the corresponding period in 2013 driving higher customer demand.

For year-to-date 2014, fuel expense was $2.06 billion compared to $1.77 billion in the corresponding period in 2013. The increase was primarily due to a 10.7% increase in the volume of KWHs generated as a result of colder weather in the first quarter 2014 and warmer weather in the second and third quarters 2014 as compared to the corresponding periods in 2013 driving higher customer demand and a 4.2% increase in the average cost of fuel per KWH generated primarily due to higher natural gas prices.

Purchased Power – Non-Affiliates

In the third quarter 2014, purchased power expense from non-affiliates was $77 million compared to $64 million in the corresponding period in 2013. The increase was due to a 4.1% increase in the average cost per KWH purchased

64

GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

primarily resulting from higher natural gas prices and a 19.0% increase in the volume of KWHs purchased to meet higher customer demand resulting from warmer weather in the third quarter 2014 as compared to the corresponding period in 2013.

For year-to-date 2014, purchased power expense from non-affiliates was $219 million compared to $175 million in the corresponding period in 2013.The increase was due to an increase of 17.5% in the average cost per KWH purchased primarily resulting from higher natural gas prices and a 7.3% increase in the volume of KWHs purchased to meet higher customer demand resulting from colder weather in the first quarter 2014 and warmer weather in the second and third quarters 2014 as compared to the corresponding periods 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 third quarter 2014, purchased power expense from affiliates was $172 million compared to $152 million in the corresponding period in 2013. The increase was due to a 23.1% increase in the volume of KWHs purchased to meet higher customer demand resulting from warmer weather in the third quarter 2014 as compared to the corresponding period in 2013.

For year-to-date 2014, purchased power expense from affiliates was $522 million compared to $503 million in the corresponding period in 2013. The increase was primarily due to a 10.1% increase in the average cost per KWH purchased reflecting higher natural gas prices, partially offset by a 2.1% 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.

Other Operations and Maintenance Expenses

Third Quarter 2014 vs. Third Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$54	13.4	$104	8.5

In the third quarter 2014, other operations and maintenance expenses were $456 million compared to $402 million in the corresponding period in 2013. The increase was primarily due to increases of $21 million in generation expenses to meet higher demand and for scheduled outage maintenance and $22 million in transmission and distribution overhead line maintenance.

For year-to-date 2014, other operations and maintenance expenses were $1.33 billion compared to $1.23 billion in the corresponding period in 2013. The increase was due to increases of $44 million in generation expenses to meet higher demand, $37 million in transmission and distribution overhead line maintenance, and $16 million in customer assistance expenses related to customer incentive and demand-side management programs.

Depreciation and Amortization

Third Quarter 2014 vs. Third Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$10	5.0	$23	3.8

In the third quarter 2014, depreciation and amortization was $211 million compared to $201 million in the corresponding period in 2013. The increase was due to decreases of $9 million and $4 million in amortization of

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GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

regulatory liabilities related to state income tax credits that was completed in December 2013 and other cost of removal obligations as authorized in the 2013 ARP, respectively, partially offset by a decrease of $6 million in depreciation and amortization also as authorized in the 2013 ARP.

For year-to-date 2014, depreciation and amortizationwas $628 million compared to $605 million in the corresponding period in 2013. The increase was due to decreases of $27 million and $12 million in amortization of regulatory liabilities related to state income tax credits that was completed in December 2013 and other cost of removal obligations as authorized in the 2013 ARP, respectively, partially offset by a decrease of $14 million in depreciation and amortization also as authorized in the 2013 ARP.

Taxes Other Than Income Taxes

Third Quarter 2014 vs. Third Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$9	8.8	$28	9.6

In the third quarter 2014, taxes other than income taxes were $111 million compared to $102 million in the corresponding period in 2013. For year-to-date 2014,taxes other than income taxes were $320 million compared to $292 million in the corresponding period in 2013.The increases were primarily due to increases of $5 million and $21 million in municipal franchise fees related to higher retail revenues and $3 million and $6 million in payroll taxes in the third quarter 2014 and year-to-date 2014, respectively.

Interest Expense, Net of Amounts Capitalized

Third Quarter 2014 vs. Third Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$(4)	(4.3)	$(17)	(6.1)

In the third quarter 2014, interest expense, net of amounts capitalized was $88 million compared to $92 million in the corresponding period in 2013. The decrease was due to a $13 million decrease in interest on long-term debt resulting from the refinancing of long-term debt at lower rates, partially offset by a $9 million increase in interest on outstanding long-term debt borrowings from the FFB.

For year-to-date 2014, interest expense, net of amounts capitalized was $262 million compared to $279 million in the corresponding period in 2013. The decrease was due to a $36 million decrease in interest on long-term debt resulting from the refinancing of long-term debt at lower rates and redemptions, partially offset by a $22 million increase in interest on outstanding long-term debt borrowings from the FFB.

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

Income Taxes

Third Quarter 2014 vs. Third Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$18	6.0	$60	10.0

In the third quarter 2014, income taxes were $317 million compared to $299 million for the corresponding period in 2013. For year-to-date 2014, income taxes were $660 million compared to $600 million in the corresponding period in 2013. The increases in income taxes were primarily due to higher pre-tax earnings.

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FUTURE EARNINGS POTENTIAL

The results of operations discussed above are not necessarily indicative of Georgia Power's future earnings potential. The level of Georgia Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Georgia Power's business of selling electricity. These factors include Georgia Power's ability to maintain a constructive regulatory environment that continues to allow for the timely recovery of prudently-incurred costs during a time of increasing costs and the completion and subsequent operation of ongoing construction projects, primarily Plant Vogtle Units 3 and 4. Future earnings in the near term will depend, in part, upon maintaining and growing sales which is subject to a number of factors. These factors include weather, competition, new energy contracts with other utilities, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in Georgia Power's service territory. Changes in regional and global economic conditions may impact sales for Georgia Power as the pace of the economic recovery remains uncertain. The timing and extent of the economic recovery will impact growth and may impact future earnings. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Georgia Power in Item 7 of the Form 10-K.

Environmental Matters

Compliance costs related to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Georgia Power's Environmental Compliance Cost Recovery tariff allows for the recovery of capital and operations and maintenance costs related to environmental controls mandated by state and federal regulations. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively affect results of operations, cash flows, and financial condition. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under "Environmental Matters" in Item 8 of the Form 10-K for additional information.

Environmental Statutes and Regulations

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Integrated Resource Plans" of Georgia Power in Item 7 of the Form 10-K and "PSC Matters – Integrated Resource Plan" herein for additional information regarding Georgia Power's plans for compliance with environmental statutes and regulations.

Air Quality

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

On April 29, 2014, the U.S. Supreme Court overturned the U.S. Court of Appeals for the District of Columbia Circuit's August 2012 decision to vacate CSAPR and remanded the case back to the U.S. Court of Appeals for the District of Columbia Circuit for further proceedings. On October 23, 2014, the U.S. Court of Appeals for the District of Columbia Circuit granted the EPA's motion to lift the stay on CSAPR implementation and approved a revised schedule under which the first phase of the rule will go into effect beginning January 1, 2015. The Southern Company system has developed and continually updates a comprehensive environmental compliance strategy to assess compliance obligations associated with current and proposed environmental requirements, including CSAPR. The ultimate financial and unit operational impact of the rule cannot be determined at this time and is dependent on

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the outcome of further legal proceedings, the manner in which the EPA and the states implement the final rule, and the development of related emissions allowance markets.

On September 17, 2014, the EPA published a supplemental proposal for the SSM rule. The EPA previously entered into a revised settlement agreement requiring the EPA to finalize the proposed rules by May 22, 2015. The proposed rule would require states subject to the rule (including Georgia, Alabama, and Florida) to revise their SSM provisions within 18 months after issuance of the final rule. The ultimate impact of the proposed SSM rule will depend on the specific provisions of the final rule, the development and implementation of rules at the state level, and the outcome of any legal challenges and cannot be determined at this time.

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

Water Quality

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

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

On August 15, 2014, the EPA published a final rule establishing standards for reducing effects on fish and other aquatic life caused by new and existing cooling water intake structures at existing power plants and manufacturing facilities, which became effective October 14, 2014. The ultimate outcome of this final rule will depend on the results of additional studies and implementation of the rule by state regulators, but could result in additional capital and operational costs associated with changes to existing intake structures and cooling systems and increased costs associated with the construction of new generating units. The ultimate impact of this rule will depend on the outcome of any legal challenges and cannot be determined at this time.

Global Climate Issues

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

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

On October 28, 2014, the EPA issued a notice of data availability related to the proposed Clean Power Plan, which was not intended to revise the EPA's proposal but to provide the public with an opportunity to consider and comment on technical issues and data related to the guidelines. The Southern Company system expects to file comments with the EPA at or prior to the EPA's December 1, 2014 extended deadline. These comments may include

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a preliminary estimated cost of complying with the proposed guidelines utilizing one of the EPA's compliance scenarios. These costs could be significant to the utility industry and the Southern Company system. However, the ultimate financial and operational impact of the Clean Power Plan proposed guidelines on the Southern Company system cannot be determined at this time and will be dependent upon numerous factors. These factors include: the structure, timing, and content of the EPA's final guidelines; individual state implementation of these guidelines, including the potential that state implementation plans impose different standards; additional rulemaking activities in response to legal challenges and court decisions; the impact of future changes in generation and emissions-related technology and costs; the impact of future decisions regarding unit retirement and replacement, including the type and amount of any such replacement capacity; and the time periods over which compliance will be required.

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

PSC Matters

Rate Plans

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Rate Plans" of Georgia Power in Item 7 and 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 on Georgia Power's 2013 ARP.

In accordance with the terms of the 2013 ARP, on October 3, 2014, Georgia Power filed the following tariff adjustments with the Georgia PSC to become effective January 1, 2015 pending its approval:

• Increase the traditional base tariffs by approximately $107 million to cover additional capacity costs;

• Increase the environmental compliance cost recovery tariff by approximately $32 million;

• Increase the demand-side management tariffs by approximately $3 million; and

• Increase the municipal franchise fee tariff by approximately $3 million, consistent with the adjustments above.

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

Renewables Development

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

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

As a result of biomass PPA amendments executed during 2014, total estimated purchased power contractual obligations decreased $392 million from December 31, 2013. Estimated purchased power contractual obligations have been updated to $641million for 2015 and 2016, $679 million for 2017 and 2018, and $3.8 billion after 2018. Estimated purchased power contractual obligations did not change for 2014. The counterparties of the aforementioned PPAs have posted collateral as required. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations – Contractual Obligations" of Georgia Power in Item 7 of the Form 10-K for additional information.

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On October 8, 2014, Georgia Power executed PPAs to purchase energy from 515 MWs of solar capacity as part of the Georgia Power Advanced Solar Initiative program. These PPAs are expected to commence in 2015 and 2016, have terms ranging from 20 to 30 years, and are subject to Georgia PSC approval.

On October 23, 2014, the Georgia PSC approved Georgia Power's request to build, own, and operate three 30-MW solar generation facilities at three U.S. Army bases by the end of 2016. In addition, Georgia Power has entered into a memorandum of understanding with the U.S. Navy to pursue a similar solar project pending Georgia PSC review.

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

Integrated Resource Plan

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

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

Fuel Cost Recovery

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

As of September 30, 2014, Georgia Power's under recovered fuel balance totaled $175 million and is included in deferred charges and other 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. Georgia Power's next fuel case is expected to be filed with the Georgia PSC by February 27, 2015.

Fuel cost recovery revenues as recorded on the financial statements are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on Georgia Power's revenues or net income, but will affect cash flow. See Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Fuel Cost Recovery" herein for additional information.

Storm Damage Recovery

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

Georgia Power defers and recovers certain costs related to damages from major storms as mandated by the Georgia PSC. As of September 30, 2014 and December 31, 2013, the balance in the regulatory asset related to storm damage was $105 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.

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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, Vogtle Construction Monitoring (VCM) reports, and pending litigation.

In 2009, the Georgia PSC approved inclusion of the Plant Vogtle Units 3 and 4 related CWIP accounts in rate base, and the State of Georgia enacted the Georgia Nuclear Energy Financing Act, which allows Georgia Power to recover financing costs for nuclear construction projects certified by the Georgia PSC. Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff by including the related CWIP accounts in rate base during the construction period. The Georgia PSC approved increases to the NCCR tariff of approximately $223 million, $35 million, $50 million, and $60 million, effective January 1, 2011, 2012, 2013, and 2014, respectively. On October 31, 2014, Georgia Power filed to increase the NCCR tariff by approximately $27 million effective January 1, 2015 pending Georgia PSC approval. 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 September 30, 2014, approximately $23 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. Associated financing costs during the construction period are estimated to total approximately $2.0 billion.

In September 2013, the Georgia PSC approved a stipulation entered into by Georgia Power and the Georgia PSC staff to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate, until the completion of Plant Vogtle Unit 3, or earlier if deemed appropriate by the Georgia PSC and Georgia Power. In accordance with the Georgia Integrated Resource Planning Act, any costs incurred by Georgia Power in excess of the certified amount will not be included in rate base, unless shown to be reasonable and prudent. In addition, financing costs on any excess construction-related costs potentially would be subject to recovery through AFUDC instead of the NCCR tariff. On August 19, 2014, the Georgia PSC approved a combined ninth and tenth VCM report covering the period from January 1 through December 31, 2013 (Ninth/Tenth VCM report), including construction capital costs incurred, which through December 31, 2013 totaled $2.6 billion. Georgia Power resumed filing semi-annual reports with the eleventh VCM report filed on August 28, 2014, which requests approval of an additional $0.2 billion in costs incurred from January 1, 2014 through June 30, 2014.

In 2012, the Vogtle 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 Vogtle 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 Vogtle Owners, and the Contractor, pursuant to which the Contractor agreed to design, engineer, procure, construct, and test Plant Vogtle Units 3 and 4 (Vogtle 3 and 4 Agreement). Also in 2012, Georgia Power and the other Vogtle Owners filed suit against the Contractor in the U.S. District Court for the Southern District of Georgia seeking a declaratory judgment that the Vogtle Owners are not responsible for these costs. In 2012, the Contractor also filed suit against Georgia Power and the other Vogtle Owners in the U.S. District Court for the District of Columbia alleging the Vogtle Owners are responsible for these costs. In August 2013, the U.S. District Court for the District of Columbia dismissed the Contractor's suit, ruling

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that the proper venue is the U.S. District Court for the Southern District of Georgia. The Contractor appealed the decision to the U.S. Court of Appeals for the District of Columbia Circuit in September 2013. The portion of additional costs claimed by the Contractor in its initial complaint that would be attributable to Georgia Power (based on Georgia Power's ownership interest) is approximately $425 million (in 2008 dollars). The Contractor also asserted it is entitled to further schedule extensions. On May 22, 2014, the Contractor filed an amended counterclaim to the suit pending in the U.S. District Court for the Southern District of Georgia alleging that (i) the design changes to the DCD imposed by the NRC delayed module production and the impacts to the Contractor are recoverable by the Contractor under the Vogtle 3 and 4 Agreement and (ii) the changes to the basemat rebar design required by the NRC caused additional costs and delays recoverable by the Contractor under the Vogtle 3 and 4 Agreement. The Contractor did not specify in its amended counterclaim the amounts relating to these new allegations, but the Contractor subsequently asserted, and may from time to time continue to assert, that it is entitled to additional payments with respect to these new allegations, any of which could be substantial. Georgia Power does not agree with either the proposed cost or schedule adjustments or that the Vogtle Owners have any responsibility for costs related to these issues. Litigation is ongoing and Georgia Power intends to vigorously defend the positions of the Vogtle Owners. Georgia Power also expects negotiations with the Contractor to continue with respect to cost and schedule during which negotiations the parties may reach a mutually acceptable compromise of their positions.

Processes are in place that are designed to assure compliance with the requirements specified in the DCD and the COLs, including inspections by Southern Nuclear and the NRC that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the NRC. Various design and other licensing-based compliance issues are expected to arise as construction proceeds, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs either to the Vogtle Owners or the Contractor or to both.

As construction continues, the risk remains that ongoing challenges with Contractor performance including additional challenges in the fabrication, assembly, delivery, and installation of the shield building and structural modules, delays in the receipt of the remaining permits necessary for the operation of Plant Vogtle Units 3 and 4, or other issues could arise and may further impact project schedule and cost. While Georgia Power expects the Contractor to employ mitigation efforts to maintain the current project schedule and believes the Contractor is responsible for any related costs, Contractor performance and progress in recent months on the assembly and installation of the shield building and structural modules have resulted in additional schedule pressure.

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

See RISK FACTORS of Georgia Power in Item 1A of the Form 10-K for a discussion of certain risks associated with the licensing, construction, and operation of nuclear generating units, including potential impacts that could result from a major incident at a nuclear facility anywhere in the world.

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

Other Matters

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

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

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

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

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

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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

Recently Issued Accounting Standards

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

FINANCIAL CONDITION AND LIQUIDITY

Overview

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

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

Net cash provided from operating activities totaled $2.07 billion for the first nine months of 2014 compared to $2.13 billion for the corresponding period in 2013. The decrease was primarily due to fuel cost recovery and storm restoration costs, partially offset by higher retail operating revenues and lower fuel inventory additions. Net cash used for investing activities totaled $1.46 billion for the first nine months of 2014 compared to $1.25 billion for the corresponding period in 2013 due to gross property additions primarily related to installation of equipment to comply with environmental standards; construction of transmission and distribution facilities; and purchase of nuclear fuel. Net cash used for financing activities totaled $577 million for the first nine months of 2014 compared to $869 million used for financing activities in the corresponding period in 2013. The decrease in cash used for financing activities is primarily due to borrowings from the FFB for the construction of Plant Vogtle Units 3 and 4, partially offset by FFB loan issuance costs and a reduction in short-term debt. Fluctuations in cash flow from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes for the first nine months of 2014 include increases of $819 million in property, plant, and equipment, $502 million in long-term debt primarily due to borrowings from the FFB, and $175 million in deferred under recovered regulatory clause revenues and decreases of $836 million in short-term debt and $337 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 $503 million will be required through September 30, 2015 to fund maturities of long-term debt, including $98 million of certain pollution control revenue bonds reclassified to securities due within one year in anticipation of redemption in connection with unit retirement decisions. See Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Integrated Resource Plans" in Item 8 of the Form 10-K for additional information regarding unit retirement decisions. Also see FUTURE EARNINGS POTENTIAL – "PSC Matters – Renewables Development" herein for additional information regarding estimated purchased power contractual obligations.

The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing units, to meet regulatory requirements; changes in FERC rules and regulations; Georgia PSC approvals; changes in the expected environmental compliance program; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. See Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Nuclear Construction" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" herein for information regarding additional factors that may impact construction expenditures.

Sources of Capital

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

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 full recourse and also are secured by a first priority lien on (i) Georgia Power's 45.7% ownership interest in Plant Vogtle Units 3 and 4 (primarily the units under construction, the related real property, and any nuclear fuel loaded in the reactor core) and (ii) Georgia Power's rights and obligations under the principal contracts relating to Plant Vogtle Units 3 and 4. Under the FFB Credit Facility, Georgia Power may make term loan borrowings through the FFB. Proceeds of borrowings made under the FFB Credit Facility will be used to reimburse Georgia Power for a portion of certain costs of construction relating to Plant Vogtle Units 3 and 4 that are eligible for financing under the Loan Guarantee Agreement (Eligible Project Costs). Aggregate borrowings under the FFB Credit Facility may not exceed the lesser of (i) 70% of Eligible Project Costs or (ii) approximately $3.46 billion. See Note 6 to the financial statements of Georgia Power in Item 8 of the Form 10-K for additional information regarding the Loan Guarantee Agreement and Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" herein for additional information regarding Plant Vogtle Units 3 and 4.

Eligible Project Costs incurred through September 30, 2014 would allow for borrowings of up to $2.0 billion under the FFB Credit Facility. Through September 30, 2014, Georgia Power has borrowed $1.0 billion under the FFB Credit Facility, leaving $1.0 billion of available borrowing ability.

Georgia Power's current liabilities frequently exceed current assets because of the continued use of short-term debt as a funding source to meet scheduled maturities of long-term debt, as well as cash needs, which can fluctuate significantly due to the seasonality of the business. Georgia Power has substantial cash flow from operating activities and access to the capital markets to meet liquidity needs.

At September 30, 2014, Georgia Power had approximately $63 million of cash and cash equivalents. Committed credit arrangements with banks at September 30, 2014 were as follows:

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

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

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 September 30, 2014 was approximately $865 million. In addition, at September 30, 2014, Georgia Power had $65 million of fixed rate pollution control revenue bonds that were required to be remarketed within the next 12 months.

Georgia Power's credit arrangements contain covenants that limit debt levels and contain cross default provisions to other indebtedness (including guarantee obligations) of Georgia Power. Such cross default provisions to other indebtedness would trigger an event of default if Georgia Power defaulted on indebtedness or guarantee obligations over a specified threshold. Georgia Power is currently in compliance with all such covenants. None of the

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 September 30, 2014			Short-term Debt During the Period(a)
	Amount Outstanding		Weighted Average Interest Rate	Average Outstanding		Weighted Average Interest Rate	Maximum Amount Outstanding
	(in millions)			(in millions)			(in millions)
Commercial paper	$	211	0.2%	$	278	0.2%	$	644

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

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

Credit Rating Risk

Georgia Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel purchases, fuel transportation and storage, energy price risk management, and construction of new generation. The maximum potential collateral requirements under these contracts at September 30, 2014 were as follows:

Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB- and/or Baa3	$	86
Below BBB- and/or Baa3	1,297

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

Financing Activities

In February 2014, Georgia Power made initial borrowings under the FFB Credit Facility in an aggregate principal amount of $1.0 billion. The interest rate applicable to $500 million of the initial advance under the FFB Credit Facility is 3.860% for an interest period that extends to 2044 and the interest rate applicable to the remaining $500 million is 3.488% for an interest period that extends to 2029 and is expected to be reset from time to time thereafter through 2044. 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. In connection with its entry into the

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

agreements with the DOE and the FFB, Georgia Power incurred issuance costs of approximately $66 million, which will be amortized over the life of the borrowings under the FFB Credit Facility.

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

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

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

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

Subsequent to September 30, 2014, Georgia Power entered into interest rate swaps to hedge exposure to interest rate changes related to existing debt. The notional amount of the swaps totaled $900 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.

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GULF POWER COMPANY

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GULF POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2014			2013			2014			2013
	(in thousands)						(in thousands)
Operating Revenues:
Retail revenues	$	365,971		$	335,916		$	979,435		$	901,343
Wholesale revenues, non-affiliates	33,689			29,431			103,616			82,533
Wholesale revenues, affiliates	20,591			16,701			96,996			65,206
Other revenues	18,083			17,313			48,950			47,726
Total operating revenues	438,334			399,361			1,228,997			1,096,808
Operating Expenses:
Fuel	164,497			136,216			478,163			397,409
Purchased power, non-affiliates	26,813			17,180			56,605			41,369
Purchased power, affiliates	3,611			15,829			19,299			30,075
Other operations and maintenance	85,097			76,964			250,425			232,472
Depreciation and amortization	38,487			37,345			109,354			111,479
Taxes other than income taxes	31,229			28,051			83,786			75,437
Total operating expenses	349,734			311,585			997,632			888,241
Operating Income	88,600			87,776			231,365			208,567
Other Income and (Expense):
Allowance for equity funds used during construction	3,195			1,663			8,276			4,318
Interest expense, net of amounts capitalized	(12,859		)	(13,988		)	(39,417		)	(42,650		)
Other income (expense), net	(627		)	(337		)	(1,857		)	(2,704		)
Total other income and (expense)	(10,291		)	(12,662		)	(32,998		)	(41,036		)
Earnings Before Income Taxes	78,309			75,114			198,367			167,531
Income taxes	29,511			28,109			74,228			62,950
Net Income	48,798			47,005			124,139			104,581
Dividends on Preference Stock	2,251			2,251			6,752			5,453
Net Income After Dividends on Preference Stock	$	46,547		$	44,754		$	117,387		$	99,128

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2014		2013		2014		2013
	(in thousands)				(in thousands)
Net Income	$	48,798	$	47,005	$	124,139	$	104,581
Other comprehensive income (loss):
Qualifying hedges:
Reclassification adjustment for amounts included in net income, net of tax of $58, $58, $175 and $238 respectively	93		93		279		379
Total other comprehensive income (loss)	93		93		279		379
Comprehensive Income	$	48,891	$	47,098	$	124,418	$	104,960

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 Nine Months Ended September 30,
	2014			2013
	(in thousands)
Operating Activities:
Net income	$	124,139		$	104,581
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	115,093			116,626
Deferred income taxes	29,359			55,911
Allowance for equity funds used during construction	(8,276		)	(4,318		)
Pension, postretirement, and other employee benefits	5,693			9,279
Stock based compensation expense	1,520			1,389
Other, net	(2,667		)	2,509
Changes in certain current assets and liabilities —
-Receivables	(45,777		)	(49,690		)
-Prepayments	2,894			2,568
-Fossil fuel stock	44,300			24,475
-Materials and supplies	1,007			(2,683		)
-Prepaid income taxes	8,627			23,515
-Other current assets	(1,022		)	—
-Accounts payable	10,097			(9,132		)
-Accrued taxes	21,858			20,648
-Accrued compensation	5,131			(5,974		)
-Over recovered regulatory clause revenues	6,834			(17,092		)
-Other current liabilities	4,939			5,258
Net cash provided from operating activities	323,749			277,870
Investing Activities:
Property additions	(254,256		)	(205,161		)
Cost of removal, net of salvage	(9,309		)	(12,563		)
Change in construction payables	1,688			6,752
Payments pursuant to long-term service agreements	(6,097		)	(3,843		)
Other investing activities	89			306
Net cash used for investing activities	(267,885		)	(214,509		)
Financing Activities:
Decrease in notes payable, net	(44,395		)	(65,077		)
Proceeds —
Common stock issued to parent	50,000			40,000
Capital contributions from parent company	2,873			1,936
Preference stock	—			50,000
Pollution control revenue bonds	42,075			63,000
Senior notes	200,000			90,000
Redemptions —
Pollution control revenue bonds	(29,075		)	(63,000		)
Senior notes	—			(90,000		)
Payment of preference stock dividends	(6,752		)	(4,753		)
Payment of common stock dividends	(92,400		)	(86,550		)
Other financing activities	(2,951		)	(3,209		)
Net cash provided from (used for) financing activities	119,375			(67,653		)
Net Change in Cash and Cash Equivalents	175,239			(4,292		)
Cash and Cash Equivalents at Beginning of Period	21,753			32,167
Cash and Cash Equivalents at End of Period	$	196,992		$	27,875
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $3,699 and $2,291 capitalized for 2014 and 2013, respectively)	$	28,574		$	33,433
Income taxes, net	35,940			(17,064		)
Noncash transactions — accrued property additions at end of period	34,876			30,846

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

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GULF POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Assets	At September 30, 2014			At December 31, 2013
	(in thousands)
Current Assets:
Cash and cash equivalents	$	196,992		$	21,753
Receivables —
Customer accounts receivable	98,357			64,884
Unbilled revenues	63,950			57,282
Under recovered regulatory clause revenues	52,531			48,282
Other accounts and notes receivable	10,131			8,620
Affiliated companies	7,405			8,259
Accumulated provision for uncollectible accounts	(1,695		)	(1,131		)
Fossil fuel stock, at average cost	90,750			135,050
Materials and supplies, at average cost	53,928			54,935
Other regulatory assets, current	42,683			18,536
Prepaid expenses	8,374			33,186
Other current assets	3,805			6,120
Total current assets	627,211			455,776
Property, Plant, and Equipment:
In service	4,444,015			4,363,664
Less accumulated provision for depreciation	1,277,290			1,211,336
Plant in service, net of depreciation	3,166,725			3,152,328
Construction work in progress	433,299			280,626
Total property, plant, and equipment	3,600,024			3,432,954
Other Property and Investments	15,212			15,314
Deferred Charges and Other Assets:
Deferred charges related to income taxes	54,856			50,597
Prepaid pension costs	11,639			11,533
Other regulatory assets, deferred	322,370			340,415
Other deferred charges and assets	38,394			30,982
Total deferred charges and other assets	427,259			433,527
Total Assets	$	4,669,706		$	4,337,571

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

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GULF POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholder's Equity	At September 30, 2014			At December 31, 2013
	(in thousands)
Current Liabilities:
Securities due within one year	$	75,000		$	75,000
Notes payable	91,483			135,878
Accounts payable —
Affiliated	82,258			76,897
Other	55,713			47,038
Customer deposits	35,188			34,433
Accrued taxes —
Accrued income taxes	16,124			45
Other accrued taxes	29,777			7,486
Accrued interest	17,808			10,272
Accrued compensation	16,839			11,657
Other regulatory liabilities, current	9,136			13,408
Liabilities from risk management activities	7,337			6,470
Other current liabilities	41,716			22,972
Total current liabilities	478,379			441,556
Long-term Debt	1,369,447			1,158,163
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	746,866			734,355
Accumulated deferred investment tax credits	3,101			4,055
Employee benefit obligations	78,004			76,338
Other cost of removal obligations	233,926			228,148
Other regulatory liabilities, deferred	50,859			56,051
Deferred capacity expense	168,574			180,149
Other deferred credits and liabilities	78,671			77,126
Total deferred credits and other liabilities	1,360,001			1,356,222
Total Liabilities	3,207,827			2,955,941
Preference Stock	146,504			146,504
Common Stockholder's Equity:
Common stock, without par value —
Authorized — 20,000,000 shares
Outstanding — September 30, 2014: 5,442,717 shares
— December 31, 2013: 4,942,717 shares	483,060			433,060
Paid-in capital	557,664			552,681
Retained earnings	275,481			250,494
Accumulated other comprehensive loss	(830		)	(1,109		)
Total common stockholder's equity	1,315,375			1,235,126
Total Liabilities and Stockholder's Equity	$	4,669,706		$	4,337,571

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

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GULF POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

THIRD QUARTER 2014 vs. THIRD QUARTER 2013

AND

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

OVERVIEW

Gulf Power operates as a vertically integrated utility providing electricity to retail customers within its traditional service area located in northwest Florida and to wholesale customers in the Southeast.

Many factors affect the opportunities, challenges, and risks of Gulf Power's business of selling electricity. These factors include the ability to maintain a constructive regulatory environment, to maintain and grow energy sales given economic conditions, and to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand growth, increasingly stringent environmental standards, reliability, restoration following major storms, and fuel. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Gulf Power for the foreseeable future.

Gulf Power continues to focus on several key performance indicators. These indicators include customer satisfaction, plant availability, system reliability, and net income after dividends on preference stock. For additional information on these indicators, see MANAGEMENT'S DISCUSSION AND ANALYSIS – OVERVIEW – "Key Performance Indicators" of Gulf Power in Item 7 of the Form 10-K.

RESULTS OF OPERATIONS

Net Income

Third Quarter 2014 vs. Third Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$1.8	4.0	$18.3	18.4

Gulf Power's net income after dividends on preference stock for the third quarter 2014 was $46.5 million compared to $44.7 million for the corresponding period in 2013. The increase was primarily due to higher retail revenues related to a base rate increase, partially offset by higher non-fuel operations and maintenance expenses.

Gulf Power's net income after dividends on preference stock for year-to-date 2014 was $117.4 million compared to $99.1 million for the corresponding period in 2013. The increase was primarily due to higher retail revenues related to a base rate increase and colder weather in the first quarter 2014, partially offset by higher non-fuel operations and maintenance expenses.

Retail Revenues

Third Quarter 2014 vs. Third Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$30.1	8.9	$78.1	8.7

In the third quarter 2014, retail revenues were $366.0 million compared to $335.9 million for the corresponding period in 2013. For year-to-date 2014, retail revenues were $979.4 million compared to $901.3 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:

	Third Quarter 2014					Year-to-Date  2014
	(in millions)			(% change)		(in millions)		(% change)
Retail – prior year	$	335.9				$	901.3
Estimated change resulting from –
Rates and pricing	11.0			3.3		33.6		3.7
Sales growth	6.1			1.8		7.7		0.9
Weather	(0.9		)	(0.3	)	10.0		1.1
Fuel and other cost recovery	13.9			4.1		26.8		3.0
Retail – current year	$	366.0		8.9	%	$	979.4	8.7	%

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

Revenues attributable to changes in sales increased in the third quarter 2014 when compared to the corresponding period in 2013. Weather-adjusted KWH energy sales to residential and commercial customers increased 5.8% and 2.6%, respectively, due to higher weather-adjusted use per customer and customer growth. KWH energy sales to industrial customers increased 6.4% due to decreased customer co-generation and changes in customers' operations.

Revenues attributable to changes in sales increased year-to-date 2014 when compared to the corresponding period in 2013. Weather-adjusted KWH energy sales to residential customers increased 1.8% due to higher weather-adjusted use per customer and customer growth. Weather-adjusted KWH energy sales to commercial customers increased 0.3% due to customer growth, partially offset by a decline in weather-adjusted use per customer. KWH energy sales to industrial customers increased 11.0% due to decreased customer co-generation and changes in customers' operations.

Fuel and other cost recovery revenues increased in the third quarter 2014 and year-to-date 2014 when compared to the corresponding periods in 2013 primarily due to higher revenues associated with recoverable fuel costs for increased generation and purchased power costs, partially offset by lower revenues associated with lower recoverable costs under Gulf Power's energy conservation and environmental cost recovery clauses. Recoverable fuel costs include the effect of a 2013 payment received pursuant to the resolution of a contract dispute.

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

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Wholesale Revenues – Non-Affiliates

Third Quarter 2014 vs. Third Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$4.3	14.5	$21.1	25.5

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

In the third quarter 2014, wholesale revenues from sales to non-affiliates were $33.7 million compared to $29.4 million for the corresponding period in 2013. The increase was primarily due to a 25.4% increase in KWH sales primarily to wholesale customers under Plant Scherer Unit 3 long-term sales agreements.

For year-to-date 2014, wholesale revenues from sales to non-affiliates were $103.6 million compared to $82.5 million for the corresponding period in 2013. The increase was primarily due to a 59.9% increase in KWH sales due to lower-priced supply alternatives from the Southern Company system's resources compared to wholesale market prices and a planned outage at Plant Scherer Unit 3 in 2013.

Wholesale Revenues – Affiliates

Third Quarter 2014 vs. Third Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$3.9	23.3	$31.8	48.8

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 third quarter 2014, wholesale revenues from sales to affiliates were $20.6 million compared to $16.7 million for the corresponding period in 2013. The increase was primarily due to an 11.7% increase in the price of energy sold to affiliates due to higher marginal generation costs and a 10.3% increase in KWH sales that resulted from more Gulf Power generation dispatched to serve affiliated companies' higher weather-related energy demand.

For year-to-date 2014, wholesale revenues from sales to affiliates were $97.0 million compared to $65.2 million for the corresponding period in 2013. The increase was primarily due to a 29.6% increase in the price of energy sold to affiliates due to higher marginal generation costs and a 14.8% increase in KWH sales that resulted from more Gulf Power generation dispatched to serve affiliated companies' higher weather-related energy demand in 2014.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Fuel and Purchased Power Expenses

	Third Quarter 2014 vs. Third Quarter 2013					Year-to-Date 2014 vs. Year-to-Date 2013
	(change in millions)			(% change)		(change in millions)			(% change)
Fuel	$	28.3		20.8		$	80.8		20.3
Purchased power – non-affiliates	9.6			56.1		15.2			36.8
Purchased power – affiliates	(12.2		)	(77.2	)	(10.8		)	(35.8	)
Total fuel and purchased power expenses	$	25.7				$	85.2

In the third quarter 2014, total fuel and purchased power expenses were $194.9 million compared to $169.2 million for the corresponding period in 2013. Total fuel and purchased power expenses for the third quarter 2013 included the effect of a 2013 payment received pursuant to the resolution of a contract dispute. Excluding that effect, higher volume of KWHs generated and purchased increased expenses $12.5 million in the third quarter 2014 due to more Gulf Power generation dispatched to serve affiliated companies' higher weather-related demand. This increase was offset by a $7.3 million decrease due to a lower average cost of fuel and purchased power.

For year-to-date 2014, total fuel and purchased power expenses were $554.1 million compared to $468.9 million for the corresponding period in 2013. Total fuel and purchased power expenses for the first nine months of 2013 included the effect of a 2013 payment received pursuant to the resolution of a contract dispute. Excluding that effect, higher volume of KWHs generated and purchased increased expenses $62.3 million year-to-date 2014 primarily due to more Gulf Power generation dispatched to serve affiliated companies' higher demand as a result of colder weather in the first quarter 2014 and warmer weather in the third quarter 2014 compared to the corresponding periods in 2013. The increased expenses also included a $2.4 million increase due to a higher average cost of fuel and purchased power.

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

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

	Third Quarter 2014	Third Quarter 2013	Year-to-Date 2014	Year-to-Date 2013
Total generation (millions of KWHs)	3,085	2,692	8,717	6,978
Total purchased power (millions of KWHs)	1,479	1,593	4,190	4,602
Sources of generation (percent) –
Coal	66	64	69	62
Gas	34	36	31	38
Cost of fuel, generated (cents per net KWH) –
Coal(a)	3.83	3.33	4.08	4.09
Gas	4.16	4.17	3.95	4.05
Average cost of fuel, generated (cents per net KWH)(a)	3.94	3.64	4.04	4.07
Average cost of purchased power (cents per net KWH)(b)	4.96	4.48	4.83	4.01

(a) 2013 cost of coal includes the effect of a payment received in 2013 pursuant to the resolution of a coal contract dispute.

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

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Fuel

In the third quarter 2014, fuel expense was $164.5 million compared to $136.2 million for the corresponding period in 2013. The increase was primarily due to a 14.6% higher volume of KWHs generated due to more Gulf Power generation dispatched to serve affiliated companies' higher demand resulting from warmer weather in the third quarter 2014. The fuel expense for the third quarter 2013 included the effect of a 2013 payment received pursuant to the resolution of a coal contract dispute. Excluding this effect, the average cost of fuel decreased 10.5% primarily due to lower-priced coal supply.

For year-to-date 2014, fuel expense was $478.2 million compared to $397.4 million for the corresponding period in 2013. The increase was primarily due to a 24.9% higher volume of KWHs generated primarily due to more Gulf Power generation dispatched to serve affiliated companies' higher demand resulting from colder weather in the first quarter 2014 and warmer weather in the third quarter 2014 compared to the corresponding periods in 2013. The fuel expense for year-to-date 2013 included the effect of a 2013 payment received pursuant to the resolution of a coal contract dispute. Excluding this effect, the average cost of fuel decreased 7.6% primarily due to lower-priced coal supply.

Purchased Power – Non-Affiliates

In the third quarter 2014, purchased power expense from non-affiliates was $26.8 million compared to $17.2 million for the corresponding period in 2013. The increase was primarily due to a 30.4% increase in the average cost per KWH purchased, which included a $9.7 million increase in capacity costs associated with a scheduled rate increase for an existing PPA, partially offset by the expiration of another PPA. The increase was partially offset by a 3.3% decrease in the volume of KWHs purchased due to the expiration of a Gulf Power PPA.

For year-to-date 2014, purchased power expense from non-affiliates was $56.6 million compared to $41.4 million for the corresponding period in 2013. The increase was primarily due to a 34.9% increase in the average cost per KWH purchased, which included a $12.8 million increase in capacity costs associated with a scheduled rate increase for an existing PPA, partially offset by the expiration of another PPA. This increase was partially offset by an 11.7% decrease in the volume of KWHs purchased due to colder regional weather conditions in the first quarter 2014 which limited the availability of market resources.

Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy 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 third quarter 2014, purchased power expense from affiliates was $3.6 million compared to $15.8 million for the corresponding period in 2013. The decrease was primarily due to a 67.0% decrease in the average cost per KWH purchased, which included a $9.2 million reduction in capacity costs primarily associated with the expiration of an existing PPA, and a 31.8% decrease in the volume of KWHs purchased due to increased generation from Gulf Power's owned units in 2014.

For year-to-date 2014, purchased power expense from affiliates was $19.3 million compared to $30.1 million for the corresponding period in 2013. The decrease was primarily due to a 44.8% decrease in the average cost per KWH purchased, which included a $12.8 million reduction in capacity costs primarily associated with the expiration of an existing PPA, partially offset by a 14.5% increase in the volume of KWHs purchased due to colder weather driving higher demand in the first quarter 2014 compared to the corresponding period in 2013.

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.

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Other Operations and Maintenance Expenses

Third Quarter 2014 vs. Third Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$8.2	10.6	$17.9	7.7

In the third quarter 2014, other operations and maintenance expenses were $85.1 million compared to $76.9 million for the corresponding period in 2013. The increase was primarily due to increases of $7.0 million in routine and planned maintenance expense at generation facilities, partially offset by a decrease of $1.8 million in marketing programs.

For year-to-date 2014, other operations and maintenance expenses were $250.4 million compared to $232.5 million for the corresponding period in 2013. The increase was primarily due to a $20.0 million increase in routine and planned maintenance expenses at generation, transmission, and distribution facilities, a $2.3 million net increase in employee compensation and benefits including pension costs, a $2.1 million increase in customer uncollectibles and collection expenses, and a $2.0 million increase in transmission service related to a third party PPA. These increases were partially offset by a $5.3 million decrease in marketing programs and a $2.9 million decrease in other energy services expenses.

The year-to-date 2014 increased expense from routine and planned maintenance at distribution facilities included $3.7 million in environmental projects that did not have a significant impact on net income since the expense was offset by environmental revenues through Gulf Power's environmental cost recovery clause. The increased expense from transmission service did not have a significant impact on net income since the expense was offset by purchased power capacity revenues through Gulf Power's purchased power capacity recovery clause. The decreased expense from marketing programs did not have a significant impact on net income since the expense was offset by energy conservation revenues through Gulf Power's energy conservation cost recovery clause. The decreased expense from other energy services did not have a significant impact on net income since the expense was generally offset by associated revenues. See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses – Purchased Power Capacity Recovery," "– Environmental Cost Recovery," and "– Energy Conservation Cost Recovery" in Item 8 of the Form 10-K for additional information.

Depreciation and Amortization

Third Quarter 2014 vs. Third Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$1.2	3.1	$(2.1)	(1.9)

In the third quarter 2014, depreciation and amortization was $38.5 million compared to $37.3 million for the corresponding period in 2013. The increase in depreciation and amortization was primarily attributable to property additions at transmission and distribution facilities.

For year-to-date 2014, depreciation and amortization was $109.4 million compared to $111.5 million for the corresponding period in 2013. As authorized by the Florida PSC in a 2013 rate order, Gulf Power recorded a $5.4 million reduction in depreciation expense in 2014. This decrease was offset by increases of $3.3 million in depreciation and amortization primarily attributable to property additions at generation, transmission, and distribution facilities.

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.

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Taxes Other Than Income Taxes

Third Quarter 2014 vs. Third Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$3.2	11.3	$8.4	11.1

In the third quarter 2014, taxes other than income taxes were $31.2 million compared to $28.0 million for the corresponding period in 2013. For year-to-date 2014, taxes other than income taxes were $83.8 million compared to $75.4 million for the corresponding period in 2013. The increases were primarily due to increases in franchise fees and gross receipts taxes as a result of higher retail revenues. Franchise fees and gross receipts taxes have no impact on net income.

Allowance for Equity Funds Used During Construction

Third Quarter 2014 vs. Third Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$1.5	92.1	$4.0	91.7

In the third quarter 2014, AFUDC equity was $3.2 million compared to $1.7 million for the corresponding period in 2013. For year-to-date 2014, AFUDC equity was $8.3 million compared to $4.3 million for the corresponding period in 2013. These increases were primarily due to increased construction related to environmental control projects at generation facilities.

Income Taxes

Third Quarter 2014 vs. Third Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$1.4	5.0	$11.2	17.9

In the third quarter 2014, income taxes were $29.5 million compared to $28.1 million for the corresponding period in 2013. For year-to-date 2014, income taxes were $74.2 million compared to $63.0 million for the corresponding period in 2013.These increases wereprimarily 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

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wholesale earnings. Gulf Power currently has long-term sales agreements for 100% of Gulf Power's ownership of that unit through 2015 and 57% through 2018. The second type, referred to as requirements service, provides that Gulf Power serves the customer's capacity and energy requirements from other Gulf Power resources.

Environmental Matters

Compliance costs related to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be recovered in retail rates or through long-term wholesale agreements on a timely basis. The State of Florida has statutory provisions that allow a utility to petition the Florida PSC for recovery of prudent environmental compliance costs that are not being recovered through base rates or any other recovery mechanism. Gulf Power's current long-term wholesale agreements contain provisions that permit charging the customer with costs incurred as a result of changes in environmental laws and regulations. The full impact of any such regulatory or legislative changes cannot be determined at this time. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified. Further, higher costs that are recovered through regulated rates or long-term wholesale agreements could contribute to reduced demand for electricity as well as impact the cost competitiveness of wholesale capacity, which could negatively affect results of operations, cash flows, and financial condition. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" and "PSC Matters – Cost Recovery Clauses – Environmental Cost Recovery" of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under "Environmental Matters" in Item 8 of the Form 10-K for additional information.

Environmental Statutes and Regulations

Air Quality

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

On April 29, 2014, the U.S. Supreme Court overturned the U.S. Court of Appeals for the District of Columbia Circuit's August 2012 decision to vacate CSAPR and remanded the case back to the U.S. Court of Appeals for the District of Columbia Circuit for further proceedings. On October 23, 2014, the U.S. Court of Appeals for the District of Columbia Circuit granted the EPA's motion to lift the stay on CSAPR implementation and approved a revised schedule under which the first phase of the rule will go into effect beginning January 1, 2015. The Southern Company system has developed and continually updates a comprehensive environmental compliance strategy to assess compliance obligations associated with current and proposed environmental requirements, including CSAPR. The ultimate financial and unit operational impact of the rule cannot be determined at this time and is dependent on the outcome of further legal proceedings, the manner in which the EPA and the states implement the final rule, and the development of related emissions allowance markets.

On September 17, 2014, the EPA published a supplemental proposal for the SSM rule. The EPA previously entered into a revised settlement agreement requiring the EPA to finalize the proposed rules by May 22, 2015. The proposed rule would require states subject to the rule (including Florida, Georgia, and Mississippi) to revise their SSM provisions within 18 months after issuance of the final rule. The ultimate impact of the proposed SSM rule will depend on the specific provisions of the final rule, the development and implementation of rules at the state level, and the outcome of any legal challenges and cannot be determined at this time.

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

Water Quality

On April 21, 2014, the EPA and the U.S. Army Corps of Engineers jointly published a proposed rule to revise the regulatory definition of waters of the U.S. for all Clean Water Act (CWA) programs, significantly expanding the

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scope of federal jurisdiction under the CWA. If finalized as proposed, this rule could significantly increase permitting and regulatory requirements and costs associated with the siting of new facilities and the installation, expansion, and maintenance of transmission and distribution lines. In addition, the rule as proposed could have significant impacts on economic development projects which could affect customer demand growth. The ultimate impact of the proposed rule will depend on the specific requirements of the final rule and the outcome of any legal challenges and cannot be determined at this time.

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

On August 15, 2014, the EPA published a final rule establishing standards for reducing effects on fish and other aquatic life caused by new and existing cooling water intake structures at existing power plants and manufacturing facilities, which became effective October 14, 2014. The ultimate outcome of this final rule will depend on the results of additional studies and implementation of the rule by state regulators, but could result in additional capital and operational costs associated with changes to existing intake structures and cooling systems and increased costs associated with the construction of new generating units. The ultimate impact of this rule will depend on the outcome of any legal challenges and cannot be determined at this time.

Global Climate Issues

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

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

On October 28, 2014, the EPA issued a notice of data availability related to the proposed Clean Power Plan, which was not intended to revise the EPA's proposal but to provide the public with an opportunity to consider and comment on technical issues and data related to the guidelines. The Southern Company system expects to file comments with the EPA at or prior to the EPA's December 1, 2014 extended deadline. These comments may include a preliminary estimated cost of complying with the proposed guidelines utilizing one of the EPA's compliance scenarios. These costs could be significant to the utility industry and the Southern Company system. However, the ultimate financial and operational impact of the Clean Power Plan proposed guidelines on the Southern Company system cannot be determined at this time and will be dependent upon numerous factors. These factors include: the structure, timing, and content of the EPA's final guidelines; individual state implementation of these guidelines, including the potential that state implementation plans impose different standards; additional rulemaking activities in response to legal challenges and court decisions; the impact of future changes in generation and emissions-related technology and costs; the impact of future decisions regarding unit retirement and replacement, including the type and amount of any such replacement capacity; and the time periods over which compliance will be required.

On June 23, 2014, the U.S. Supreme Court struck down a portion of the EPA's program for GHG permitting under the Prevention of Significant Deterioration and Title V operating permit programs, holding that a facility's GHG emissions alone could not trigger a requirement to obtain a permit and that the EPA did not have the authority to

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tailor the statutory permitting thresholds. The ultimate impact of the U.S. Supreme Court's decision 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 retail ROE range then in effect. Gulf Power recognized a $5.4 million reduction in depreciation expense in the first nine months of 2014.

Cost Recovery Clauses

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "PSC Matters – Cost Recovery Clauses" of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses" in Item 8 of the Form 10-K for additional information regarding Gulf Power's recovery of retail costs through various regulatory clauses and accounting orders. Gulf Power has four regulatory clauses which are approved by the Florida PSC. The recovery balance of each regulatory clause for Gulf Power is reported in Note (B) to the Condensed Financial Statements herein.

On October 22, 2014, the Florida PSC approved Gulf Power's annual rate clause request for its fuel, purchased power capacity, environmental, and energy conservation cost recovery factors for 2015. The net effect of the approved changes is a $41.2 million increase in annual revenue for 2015. The increased revenues will not have a significant impact on net income since most of the revenues will be offset by expenses.

Retail Fuel Cost Recovery

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

Gulf Power has established fuel cost recovery rates as approved annually by the Florida PSC. In late 2013 and the first half of 2014, Gulf Power experienced higher than expected costs for natural gas and purchased power. If the projected year-end fuel cost over or under recovery balance exceeds 10% of the projected fuel revenues for the period, Gulf Power is required to notify the Florida PSC and indicate if an adjustment to the fuel recovery factor is being requested. Gulf Power filed such notice with the Florida PSC on July 18, 2014, but no adjustment to the factor was requested for 2014. Under recovered fuel costs at September 30, 2014 totaled $41.3 million and are included in under recovered regulatory clause revenues on Gulf Power's Condensed Balance Sheet herein. Fuel cost recovery revenues, as recorded on the financial statements, are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, any changes in the billing factor would have no significant effect on Gulf Power's revenues or net income, but will affect cash flow.

Other Matters

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

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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.

Recently Issued Accounting Standards

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

FINANCIAL CONDITION AND LIQUIDITY

Overview

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

Net cash provided from operating activities totaled $323.7 million for the first nine months of 2014 compared to $277.9 million for the corresponding period in 2013. The $45.8 million increase in net cash was primarily due to changes in cash flows related to clause recovery, a decrease in fossil fuel stock, and an increase in accounts payable, offset by a decrease in deferred income taxes. Net cash used for investing activities totaled $267.9 million in the first nine months of 2014 primarily due to property additions to utility plant. Net cash provided from financing activities totaled $119.4 million for the first nine months of 2014 primarily due to the issuance of long-term debt and common stock, partially offset by the payment of common stock dividends, notes payable, and the redemption of long-term debt. Fluctuations in cash flow from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes for the first nine months of 2014 include increases of $211.3 million in long-term debt, $175.2 million in cash and cash equivalents, $167.1 million in net property, plant, and equipment, and $50.0

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million in common stock due to the issuance of common stock to Southern Company. Decreases included $44.4 million in notes payable and $44.3 million in fossil fuel stock resulting from an increase in KWH generation.

Capital Requirements and Contractual Obligations

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Gulf Power in Item 7 of the Form 10-K for a description of Gulf Power's capital requirements for its construction program, including estimated capital expenditures to comply with existing environmental statutes and regulations, scheduled maturities of long-term debt, as well as related interest, leases, derivative obligations, preference stock dividends, purchase commitments, trust funding requirements, and unrecognized tax benefits. Approximately $75 million was required through September 30, 2015 to fund maturities of long-term debt. Subsequent to September 30, 2014, Gulf Power repaid at maturity the $75 million of securities due within one year.

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

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 September 30, 2014, Gulf Power had approximately $197.0 million of cash and cash equivalents. Committed credit arrangements with banks at September 30, 2014 were as follows:

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

(a) No credit arrangements expire in 2018.

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

Most of these arrangements contain covenants that limit debt levels and contain cross default provisions to other indebtedness (including guarantee obligations) that are restricted only to the indebtedness of Gulf Power. Such cross default provisions to other indebtedness would trigger an event of default if Gulf Power defaulted on indebtedness

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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. 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 September 30, 2014 was approximately $69 million. In addition, at September 30, 2014, Gulf Power had $78 million of fixed rate pollution control revenue bonds that are required to be remarketed within the next 12 months.

Gulf Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Gulf Power and the other traditional operating companies. Proceeds from such issuances for the benefit of Gulf Power are loaned directly to Gulf Power. The obligations of each company under these arrangements are several and there is no cross-affiliate credit support.

Details of short-term borrowings were as follows:

	Short-term Debt at September 30, 2014			Short-term Debt During the Period(a)
	Amount Outstanding		Weighted Average Interest Rate	Average Outstanding		Weighted Average Interest Rate	Maximum Amount Outstanding
	(in millions)			(in millions)			(in millions)
Commercial paper	$	92	0.2%	$	106	0.2%	$	139

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

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

Credit Rating Risk

Gulf Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, and energy price risk management. The maximum potential collateral requirements under these contracts at September 30, 2014 were as follows:

Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB- and/or Baa3	$	74
Below BBB- and/or Baa3	425

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 third quarter 2014 has not changed materially compared to the December 31, 2013 reporting period. Gulf Power's exposure to market volatility in

95

GULF POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

commodity fuel prices and prices of electricity with respect to its wholesale generating capacity is limited because its long-term sales agreements shift substantially all fuel cost responsibility to the purchaser. However, Gulf Power could become exposed to market volatility in energy-related commodity prices to the extent any wholesale generating capacity is uncontracted. Gulf Power currently has long-term sales agreements for 100% of its wholesale capacity through 2015 and 57% through 2018. For an in-depth discussion of Gulf Power's market risks, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of Gulf Power in Item 7 of the Form 10-K.

Financing Activities

In January 2014, Gulf Power issued 500,000 shares of common stock to Southern Company and realized proceeds of $50 million. The proceeds were used to repay a portion of Gulf Power's short-term debt and for other general corporate purposes, including Gulf Power's continuous construction program.

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

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

In September 2014, Gulf Power issued $200 million aggregate principal amount of Series 2014A 4.55% Senior Notes due October 1, 2044. The proceeds were used to repay a portion of its outstanding short-term indebtedness, for general corporate purposes, including Gulf Power's continuous construction program, and subsequent to September 30, 2014, for repayment at maturity $75 million aggregate principal amount of Gulf Power's Series K 4.90% Senior Notes due October 1, 2014.

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.

96

MISSISSIPPI POWER COMPANY

97

MISSISSIPPI POWER COMPANY

CONDENSED STATEMENTS OF OPERATIONS (UNAUDITED)

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2014			2013			2014			2013
	(in thousands)						(in thousands)
Operating Revenues:
Retail revenues	$	228,331		$	230,710		$	646,695		$	613,274
Wholesale revenues, non-affiliates	82,952			82,937			254,642			219,984
Wholesale revenues, affiliates	38,639			6,999			81,593			31,242
Other revenues	4,701			4,560			13,829			13,075
Total operating revenues	354,623			325,206			996,759			877,575
Operating Expenses:
Fuel	168,708			138,148			458,976			384,905
Purchased power, non-affiliates	3,475			2,077			16,163			5,222
Purchased power, affiliates	1,966			14,691			16,630			28,302
Other operations and maintenance	65,758			56,907			191,923			166,175
Depreciation and amortization	23,382			22,202			70,318			67,644
Taxes other than income taxes	22,344			21,071			63,198			60,760
Estimated loss on Kemper IGCC	418,000			150,000			798,000			1,062,000
Total operating expenses	703,633			405,096			1,615,208			1,775,008
Operating Income (Loss)	(349,010		)	(79,890		)	(618,449		)	(897,433		)
Other Income and (Expense):
Allowance for equity funds used during construction	32,223			32,624			107,685			87,740
Interest expense, net of amounts capitalized	(9,416		)	(8,728		)	(34,071		)	(29,526		)
Other income (expense), net	(7,764		)	(375		)	(11,496		)	(4,184		)
Total other income and (expense)	15,043			23,521			62,118			54,030
Earnings (Loss) Before Income Taxes	(333,967		)	(56,369		)	(556,331		)	(843,403		)
Income taxes (benefit)	(139,330		)	(32,687		)	(253,007		)	(355,156		)
Net Income (Loss)	(194,637		)	(23,682		)	(303,324		)	(488,247		)
Dividends on Preferred Stock	433			433			1,299			1,299
Net Income (Loss) After Dividends on Preferred Stock	$	(195,070	)	$	(24,115	)	$	(304,623	)	$	(489,546	)

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (UNAUDITED)

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2014			2013			2014			2013
	(in thousands)						(in thousands)
Net Income (Loss)	$	(194,637	)	$	(23,682	)	$	(303,324	)	$	(488,247	)
Other comprehensive income (loss):
Qualifying hedges:
Reclassification adjustment for amounts included in net income, net of tax of $131, $131, $394 and $394, respectively	212			212			637			637
Total other comprehensive income (loss)	212			212			637			637
Comprehensive Income (Loss)	$	(194,425	)	$	(23,470	)	$	(302,687	)	$	(487,610	)

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 Nine Months Ended September 30,
	2014			2013
	(in thousands)
Operating Activities:
Net income (loss)	$	(303,324	)	$	(488,247	)
Adjustments to reconcile net income (loss) to net cash provided from operating activities —
Depreciation and amortization, total	77,774			68,436
Deferred income taxes	158,552			(391,143		)
Investment tax credits	(108,171		)	45,228
Allowance for equity funds used during construction	(107,685		)	(87,740		)
Regulatory assets associated with Kemper IGCC	(51,875		)	(23,545		)
Estimated loss on Kemper IGCC	798,000			1,062,000
Kemper regulatory deferral	111,828			61,997
Other, net	12,105			23,697
Changes in certain current assets and liabilities —
-Receivables	(30,452		)	(40,003		)
-Under recovered regulatory clause revenues	(17,845		)	—
-Fossil fuel stock	35,917			59,608
-Materials and supplies	(9,080		)	(8,029		)
-Prepaid income taxes	(90,401		)	33,793
-Other current assets	5,173			(1,710		)
-Accounts payable	27,511			17,397
-Accrued taxes	(17,032		)	(2,334		)
-Accrued interest	23,939			15,153
-Accrued compensation	7,993			(8,543		)
-Over recovered regulatory clause revenues	(18,358		)	(49,247		)
-Other current liabilities	154			—
Net cash provided from operating activities	504,723			286,768
Investing Activities:
Property additions	(986,019		)	(1,221,519		)
Cost of removal, net of salvage	(7,431		)	(5,769		)
Construction payables	(40,301		)	(6,200		)
Capital grant proceeds	—			4,500
Investment in restricted cash	(10,548		)	—
Distribution of restricted cash	9,104			—
Proceeds from asset sales	—			79,020
Other investing activities	(14,804		)	(3,659		)
Net cash used for investing activities	(1,049,999		)	(1,153,627		)
Financing Activities:
Proceeds —
Capital contributions from parent company	310,860			601,197
Bonds — Other	22,866			31,092
Interest-bearing refundable deposit	75,000			—
Long-term debt issuance to parent company	220,000			—
Other long-term debt issuances	250,000			475,000
Redemptions —
Bonds — Other	—			(82,563		)
Capital leases	(1,893		)	(82		)
Long-term debt to parent company	(220,000		)	—
Other long-term debt	—			(125,000		)
Payment of preferred stock dividends	(1,299		)	(1,299		)
Payment of common stock dividends	—			(71,956		)
Return of capital	(164,790		)	(60,614		)
Other financing activities	(687		)	(1,845		)
Net cash provided from financing activities	490,057			763,930
Net Change in Cash and Cash Equivalents	(55,219		)	(102,929		)
Cash and Cash Equivalents at Beginning of Period	145,165			145,008
Cash and Cash Equivalents at End of Period	$	89,946		$	42,079
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (paid $55,376 and $53,450, net of $50,446 and $37,882 capitalized for 2014 and 2013, respectively)	$	4,930		$	15,568
Income taxes, net	(210,465		)	(48,307		)
Noncash transactions — accrued property additions at end of period	123,894			208,663
Noncash transactions — capital lease obligation	—			82,915

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 September 30, 2014			At December 31, 2013
	(in thousands)
Current Assets:
Cash and cash equivalents	$	89,946		$	145,165
Receivables —
Customer accounts receivable	53,593			40,978
Unbilled revenues	38,575			38,895
Under recovered regulatory clause revenues	17,845			—
Other accounts and notes receivable	3,995			4,600
Affiliated companies	53,682			34,920
Accumulated provision for uncollectible accounts	(1,980		)	(3,018		)
Fossil fuel stock, at average cost	77,368			113,285
Materials and supplies, at average cost	55,166			45,347
Other regulatory assets, current	53,854			52,496
Prepaid income taxes	162,790			34,751
Other current assets	4,676			9,357
Total current assets	609,510			516,776
Property, Plant, and Equipment:
In service	4,323,501			3,458,770
Less accumulated provision for depreciation	1,149,432			1,095,352
Plant in service, net of depreciation	3,174,069			2,363,418
Construction work in progress	1,987,789			2,586,031
Total property, plant, and equipment	5,161,858			4,949,449
Other Property and Investments	6,863			4,857
Deferred Charges and Other Assets:
Deferred charges related to income taxes	197,278			139,834
Other regulatory assets, deferred	255,430			200,620
Accumulated deferred income taxes	25,255			—
Other deferred charges and assets	54,929			36,673
Total deferred charges and other assets	532,892			377,127
Total Assets	$	6,311,123		$	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 September 30, 2014			At December 31, 2013
	(in thousands)
Current Liabilities:
Securities due within one year	$	811,751		$	13,789
Interest-bearing refundable deposit	225,000			150,000
Accounts payable —
Affiliated	90,488			70,299
Other	177,212			210,191
Customer deposits	14,946			14,379
Accrued taxes —
Accrued income taxes	92,018			5,590
Other accrued taxes	65,375			77,958
Accrued interest	70,956			47,144
Accrued compensation	17,317			9,324
Other regulatory liabilities, current	10,138			24,981
Over recovered regulatory clause liabilities	—			18,358
Other current liabilities	21,634			21,413
Total current liabilities	1,596,835			663,426
Long-term Debt	1,633,394			2,167,067
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	159,061			72,808
Deferred credits related to income taxes	6,639			9,145
Accumulated deferred investment tax credits	283,382			284,248
Employee benefit obligations	94,539			94,430
Asset retirement obligations	42,624			41,197
Other cost of removal obligations	162,274			151,340
Other regulatory liabilities, deferred	263,531			140,880
Other deferred credits and liabilities	15,037			14,337
Total deferred credits and other liabilities	1,027,087			808,385
Total Liabilities	4,257,316			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	2,525,056			2,376,595
Accumulated deficit	(534,493		)	(229,871		)
Accumulated other comprehensive loss	(7,227		)	(7,864		)
Total common stockholder's equity	2,021,027			2,176,551
Total Liabilities and Stockholder's Equity	$	6,311,123		$	5,848,209

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

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MISSISSIPPI POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

THIRD QUARTER 2014 vs. THIRD QUARTER 2013

AND

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

OVERVIEW

Mississippi Power operates as a vertically integrated utility providing electricity to retail customers within its traditional service territory located within the State of Mississippi and to wholesale customers in the Southeast.

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

On October 27, 2014, Mississippi Power further revised its cost estimate for the Kemper IGCC to approximately $4.86 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 the extension of the project schedule for the Kemper IGCC as a result of matters related to the time expected to be required for start-up activities and operational readiness, including enhancing the scope of specialized operator training.

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 pre-tax charges to income for the estimated probable losses on the Kemper IGCC of $418.0 million ($258.1 million after tax) in the third quarter 2014 resulting in an estimated probable loss of $798.0 million ($492.8 million after tax) for the first nine months of 2014. In the aggregate, Mississippi Power has incurred charges of $1.98 billion ($1.22 billion after tax) as a result of changes in the cost estimate for the Kemper IGCC through September 30, 2014.

Mississippi Power placed the combined cycle and the associated common facilities portion of the Kemper IGCC project in service on August 9, 2014 and continues to focus on completing the remainder of the Kemper IGCC, including the gasifier and the gas clean-up facilities. The in-service date for the remainder of the Kemper IGCC is currently expected to occur in the first half of 2016. The revised cost estimate above includes costs through March 31, 2016. As a result of the additional factors that have the potential to impact start-up and operational readiness activities for this first-of-a-kind technology as described herein, the risk of further schedule extensions and/or cost increases, which could be material, remains.

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

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MISSISSIPPI POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Mississippi Power's current liabilities exceeded current assets by approximately $1 billion at September 30, 2014, primarily because of securities due within a year. Management intends to utilize equity contributions and/or loans from Southern Company and cash, as well as commercial paper, lines of credit, and bank notes, as market conditions permit, to fund Mississippi Power's capital needs.

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

RESULTS OF OPERATIONS

Net Income (Loss)

Third Quarter 2014 vs. Third Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$(171.0)	N/M	$184.9	37.8

N/M – Not meaningful

Mississippi Power's net loss after dividends on preferred stock for the third quarter 2014 was $195.1 million compared to $24.1 million for the corresponding period in 2013. The change was primarily related to a $418.0 million pre-tax charge ($258.1 million after tax) in the third quarter 2014 compared to a $150.0 million pre-tax charge ($92.6 million after tax) in the third quarter 2013 for a revision of the estimated costs expected to be incurred on Mississippi Power's construction of the Kemper IGCC above the $2.88 billion cost cap established by the Mississippi PSC, net of the DOE Grants and excluding the Cost Cap Exceptions. The change was partially offset by an increase in revenues primarily due to retail and wholesale base rate increases and the recognition as revenue of a portion of the retail rate increase related to the Kemper IGCC cost recovery that became effective on March 19, 2013.

For year-to-date 2014, the net loss after dividends on preferred stock was $304.6 million compared to $489.5 million for the corresponding period in 2013. The change was primarily related to a $798.0 million pre-tax charge ($492.8 million after tax) in 2014 compared to $1.06 billion in pre-tax charges ($655.8 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 change was also related to an increase in AFUDC equity primarily related to the construction of the Kemper IGCC and an increase in revenues primarily due to retail and wholesale base rate increases and the recognition as revenue of a portion of the retail rate increase related to the Kemper IGCC cost recovery that became effective on March 19, 2013. The change was partially offset by increases in non-fuel operations and maintenance expenses.

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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MISSISSIPPI POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Retail Revenues

Third Quarter 2014 vs. Third Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$(2.4)	(1.0)	$33.4	5.4

In the third quarter 2014, retail revenues were $228.3 million compared to $230.7 million for the corresponding period in 2013. For year-to-date 2014, retail revenues were $646.7 million compared to $613.3 million for the corresponding period in 2013.

Details of the changes in retail revenues were as follows:

	Third Quarter 2014					Year-to-Date  2014
	(in millions)			(% change)		(in millions)			(% change)
Retail – prior year	$	230.7				$	613.3
Estimated change resulting from –
Rates and pricing	2.8			1.2		16.4			2.7
Sales decline	(3.3		)	(1.4	)	(3.6		)	(0.6	)
Weather	4.8			2.1		6.3			1.0
Fuel and other cost recovery	(6.7		)	(2.9	)	14.3			2.3
Retail – current year	$	228.3		(1.0	)%	$	646.7		5.4	%

Revenues associated with changes in rates and pricing increased in the third quarter 2014 when compared to the corresponding period in 2013 due to the collection of Kemper IGCC cost recovery revenues, the majority of which were deferred to a regulatory liability. The collected revenue for third quarter 2014 was $47.6 million compared to $37.0 million for the corresponding period in 2013, with deferrals of $41.8 million in 2014 and $34.0 million in 2013.

Revenues associated with changes in rates and pricing increased year-to-date 2014 when compared to the corresponding period in 2013 due to the collection of Kemper IGCC cost recovery revenues, the majority of which were deferred to a regulatory liability, and a $2.8 million PEP base rate increase, which both became effective March 2013. The collected Kemper IGCC cost recovery revenue for year-to-date 2014 was $121.9 million compared to $68.1 million for the corresponding period in 2013, with deferrals of $105.1 million in 2014 and $60.1 million in 2013. Also contributing to the increase was 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 – Rate Recovery of Kemper IGCC Costs" and "Retail Regulatory Matters – Performance Evaluation Plan" in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.

Revenues attributable to changes in sales decreased in the third quarter and year-to-date 2014 when compared to the corresponding periods in 2013. Weather-adjusted KWH energy sales to residential customers decreased 5.5% in the third quarter and 2.7% for year-to-date 2014 when compared to the corresponding periods in 2013 due to lower average usage per customer. Household income, one of the primary drivers of residential customer usage, has been flat in 2014. Weather-adjusted KWH energy sales to commercial customers decreased 1.8% in the third quarter and 0.5% for year-to-date 2014 when compared to the corresponding periods in 2013 due to decreased commercial economic activity. KWH energy sales to industrial customers increased 2.5% in the third quarter and 3.2% for year-to-date 2014 when compared to the corresponding periods in 2013 due to increased usage by larger customers.

104

MISSISSIPPI POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Fuel and other cost recovery revenues decreased in the third quarter 2014 when compared to the corresponding period in 2013, primarily as a result of lower recoverable fuel costs. Fuel and other cost recovery revenues increased year-to-date 2014 when compared to the corresponding period in 2013 primarily as a result of higher recoverable fuel costs resulting from an increase in Mississippi Power's generation and higher natural gas 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

Third Quarter 2014 vs. Third Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$0.1	—	$34.6	15.8

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 third quarter 2014, wholesale revenues from sales to non-affiliates were $83.0 million compared to $82.9 million for the corresponding period in 2013. The increase was due to a $2.0 million increase in base revenues primarily resulting from a wholesale base rate increase effective beginning May 1, 2014, partially offset by a $1.9 million decrease in energy revenues.

For year-to-date 2014, wholesale revenues from sales to non-affiliates were $254.6 million compared to $220.0 million for the corresponding period in 2013. The increase was due to a $17.2 million increase in base revenues primarily resulting from wholesale base rate increases effective April 1, 2013 and May 1, 2014 and a $17.4 million increase in energy revenues, of which $5.1 million was primarily associated with higher fuel prices and $12.3 million was associated with an increase in KWH sales primarily due to the higher demand resulting from colder weather in the first quarter 2014 compared to the corresponding period in 2013.

Wholesale Revenues – Affiliates

Third Quarter 2014 vs. Third Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$31.6	N/M	$50.4	N/M

N/M – Not meaningful

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 third quarter 2014, wholesale revenues from sales to affiliates were $38.6 million compared to $7.0 million for the corresponding period in 2013. The increase was due to a $33.7 million increase in energy revenues

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primarily due to placing the Kemper IGCC combined cycle in service. These increased revenues are offset by fuel expense. Of the $33.7 million increase in energy revenues, $31.6 million was associated with an increase in KWH sales due to higher gas and coal generation and $2.1 million was associated with higher prices, partially offset by a $2.1 million decrease in capacity revenues.

For year-to-date 2014, wholesale revenues from sales to affiliates were $81.6 million compared to $31.2 million for the corresponding period in 2013. The increased revenues were driven by $48.0 million associated with an increase in KWH sales primarily due to higher natural gas prices resulting in higher coal-fired generation at lower coal prices and $4.6 million associated with higher prices, partially offset by a $2.2 million decrease in capacity revenues.

Fuel and Purchased Power Expenses

	Third Quarter 2014 vs. Third Quarter 2013				Year-to-Date 2014 vs. Year-to-Date 2013
	(change in millions)			(% change)	(change in millions)			(% change)
Fuel	$	30.5		22.1	$	74.1		19.2
Purchased power – non-affiliates	1.4			67.3	11.0			N/M
Purchased power – affiliates	(12.7		)	(86.6)	(11.7		)	(41.2	)
Total fuel and purchased power expenses	$	19.2			$	73.4

N/M – Not meaningful

In the third quarter 2014, total fuel and purchased power expenses were $174.1 million compared to $154.9 million for the corresponding period in 2013. The increase was due to a $39.4 million increase in the total volume of KWHs generated, partially offset by a $20.2 million decrease in the cost of fuel and purchased power.

For year-to-date 2014, total fuel and purchased power expenses were $491.8 million compared to $418.4 million for the corresponding period in 2013. The increase was due to a $91.8 million increase in the total volume of KWHs generated, partially offset by an $18.5 million decrease 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:

	Third Quarter 2014	Third Quarter 2013	Year-to-Date 2014	Year-to-Date 2013
Total generation (millions of KWHs)(a)	5,022	3,688	12,996	10,645
Total purchased power (millions of KWHs)	125	469	591	1,070
Sources of generation (percent)(a) –
Coal	43	43	45	38
Gas	57	57	55	62
Cost of fuel, generated (cents per net KWH) –
Coal	3.97	5.12	4.12	5.01
Gas(a)	3.20	3.08	3.45	3.14
Average cost of fuel, generated (cents per net KWH)(a)	3.55	4.03	3.77	3.91
Average cost of purchased power (cents per net KWH)(a)	4.36	3.58	5.55	3.13

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

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Fuel

In the third quarter 2014, fuel expense was $168.7 million compared to $138.2 million for the corresponding period in 2013. The increase was primarily due to a 38.6% increase in the volume of KWHs generated to meet demand attributed to industrial consumption and warmer weather in the third quarter 2014 as compared to the corresponding period in 2013, partially offset by an 11.9% decrease in the average cost of fuel per KWH generated primarily due to higher coal-fired generation at lower coal prices, partially offset by higher natural gas prices.

For year-to-date 2014, fuel expense was $459.0 million compared to $384.9 million for the corresponding period in 2013. The increase was primarily due to a 23.9% 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, partially offset by a 3.6% decrease in the average cost of fuel per KWH generated, primarily due to higher natural gas prices resulting in higher coal-fired generation at lower coal prices.

Purchased Power - Non-Affiliates

In the third quarter 2014, purchased power expense from non-affiliates was $3.5 million compared to $2.1 million for the corresponding period in 2013. The increase was primarily the result of a 145.8% increase in the average cost per KWH purchased, partially offset by a 32.0% decrease in the volume of KWHs purchased.

For year-to-date 2014, purchased power expense from non-affiliates was $16.2 million compared to $5.2 million for the corresponding period in 2013. The increase was primarily due to a 283.8% increase in the average cost per KWH purchased, partially offset by a 19.4% decrease in the volume of KWHs purchased.

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

Purchased Power - Affiliates

In the third quarter 2014, purchased power expense from affiliates was $2.0 million compared to $14.7 million for the corresponding period in 2013. The decrease was primarily due to an 83.4% decrease in the volume of KWHs purchased and a 19.5% decrease in the average cost per KWH purchased.

For year-to-date 2014, purchased power expense from affiliates was $16.6 million compared to $28.3 million for the corresponding period in 2013. The decrease was primarily due to a 52.8% decrease in the volume of KWHs purchased, partially offset by a 24.5% 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

Third Quarter 2014 vs. Third Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$8.9	15.6	$25.7	15.5

In the third quarter 2014, other operations and maintenance expenses were $65.8 million compared to $56.9 million for the corresponding period in 2013. The increase was primarily due to a $4.0 million increase in employee compensation and benefits and labor, a $2.3 million increase in customer accounting services and sales expenses primarily due to uncollectible expenses and customer incentives, a $1.9 million increase in administrative and general expenses primarily due to an increase in charges from affiliates and a $1.5 million increase in transmission and distribution expenses mainly for overhead line maintenance and vegetation management. These increases were partially offset by a $0.7 million decrease in generation maintenance expenses primarily related to scheduled outages.

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For year-to-date 2014, other operations and maintenance expenses were $191.9 million compared to $166.2 million for the corresponding period in 2013. The increase was primarily due to an $11.8 million increase in employee compensation and benefits and labor, a $10.5 million increase in generation maintenance expenses primarily related to scheduled outages, and a $2.7 million increase in transmission and distribution maintenance expenses primarily for overhead line maintenance, vegetation management and equipment maintenance.

Depreciation and Amortization

Third Quarter 2014 vs. Third Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$1.2	5.3	$2.7	4.0

In the third quarter 2014, depreciation and amortization was $23.4 million compared to $22.2 million for the corresponding period in 2013. The $1.2 million increase was primarily due to a $0.6 million increase in depreciation related to increases in generation and transmission plant in service and a $0.3 million increase in amortization primarily resulting from the 2013 regulatory deferral associated with the capital lease related to the Kemper IGCC air separation unit.

For year-to-date 2014, depreciation and amortization was $70.3 million compared to $67.6 million for the corresponding period in 2013. The $2.7 million increase was primarily due to a $1.6 million increase in depreciation related to increases in generation and transmission plant in service and a $1.9 million increase in the regulatory deferral associated with the purchase of Plant Daniel Units 3 and 4. These increases were partially offset by a $0.6 million decrease in amortization resulting from regulatory deferrals associated with the Kemper IGCC.

See Note 1 to the financial statements of Mississippi Power under "Purchase of the Plant Daniel Combined Cycle Generating Units" and "Depreciation, Depletion, and Amortization" in Item 8 of the Form 10-K for additional information. See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.

Taxes Other Than Income Taxes

Third Quarter 2014 vs. Third Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$1.2	6.0	$2.4	4.0

In the third quarter 2014, taxes other than income taxes were $22.3 million compared to $21.1 million for the corresponding period in 2013. The increase was primarily due to a $1.4 million increase in ad valorem taxes and a $0.4 million increase in payroll taxes due to an increase in labor expenses, partially offset by a $0.5 million decrease primarily in corporate franchise taxes.

For year-to-date 2014, taxes other than income taxes were $63.2 million compared to $60.8 million for the corresponding period in 2013. The increase was primarily due to a $1.4 million increase in ad valorem taxes and a $1.0 million increase in payroll taxes due to an increase in labor expenses.

Estimated Loss on Kemper IGCC

Third Quarter 2014 vs. Third Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$268.0	N/M	$(264.0)	(24.9)

N/M – Not meaningful

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In the third quarter 2014 and the third quarter 2013, estimated probable losses on the Kemper IGCC of $418.0 million and $150.0 million, respectively, were recorded at Mississippi Power. For year-to-date 2014 and year-to-date 2013, estimated probable losses on the Kemper IGCC of $798.0 million and $1.06 billion, respectively, were recorded at Mississippi Power. These losses reflect revisions of estimated costs expected to be incurred on the construction of the Kemper IGCC in excess of the $2.88 billion cost cap established by the Mississippi PSC, net of the DOE Grants and excluding the Cost Cap Exceptions.

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

Allowance for Equity Funds Used During Construction

Third Quarter 2014 vs. Third Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$(0.4)	(1.2)	$20.0	22.7

For year-to-date 2014, AFUDC equity was $107.7 million compared to $87.7 million for the corresponding period in 2013. The increase was primarily due to $16.8 million related to the construction of the Kemper IGCC and $3.2 million related to the Plant Daniel scrubber project. 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

Third Quarter 2014 vs. Third Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$0.7	7.9	$4.5	15.4

In the third quarter 2014, interest expense, net of amounts capitalized was $9.4 million compared to $8.7 million for the corresponding period in 2013. The increase was primarily due to a $2.5 million increase resulting from the receipt of a $75.0 million interest-bearing refundable deposit from SMEPA in January 2014 related to its pending purchase of an undivided interest in the Kemper IGCC, a $1.9 million increase related to the regulatory liability for Kemper IGCC rate recovery, and a $1.5 million increase associated with issuances of new long-term debt. These increases were partially offset by a $4.0 million increase in capitalized interest primarily resulting from AFUDC debt and carrying costs related to the Kemper IGCC and a $0.9 million decrease in interest expense associated with the redemption of long-term debt in 2013.

For year-to-date 2014, interest expense, net of amounts capitalized was $34.0 million compared to $29.5 million for the corresponding period in 2013. The increase was primarily due to a $7.3 million increase resulting from the receipt of a $75.0 million interest-bearing refundable deposit from SMEPA in January 2014 related to its pending purchase of an undivided interest in the Kemper IGCC, a $4.9 million increase related to the regulatory liability for Kemper IGCC rate recovery, and a $3.7 million increase associated with issuances of new long-term debt. These increases were partially offset by an $8.1 million increase in capitalized interest primarily resulting from AFUDC debt and carrying costs related to the Kemper IGCC and a $2.8 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

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Cycle" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.

Other Income (Expense), Net

Third Quarter 2014 vs. Third Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$(7.4)	N/M	$(7.3)	N/M

N/M – Not meaningful

In the third quarter 2014, other income (expense), net was $(7.8) million compared to $(0.4) million for the corresponding period in 2013. For year-to-date 2014, other income (expense), net was $(11.5) million compared to $(4.2) million for the corresponding period in 2013. These changes in expense were primarily due to a settlement with the Sierra Club in 2014. See "Other Matters – Sierra Club Settlement Agreement" and Note (B) to the Condensed Financial Statements under "Other Matters – Sierra Club Settlement Agreement" herein for additional information.

Income Taxes (Benefit)

Third Quarter 2014 vs. Third Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$(106.6)	N/M	$102.2	28.8

N/M – Not meaningful

In the third quarter 2014, income tax benefits were $139.3 million compared to $32.7 million for the corresponding period in 2013. For year-to-date 2014, income tax benefits were $253.0 million compared to $355.2 million for the corresponding period in 2013. These changes were primarily 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 allows for the timely recovery of prudently-incurred costs during a time of increasing costs and the completion and subsequent operation of ongoing construction projects, primarily the Kemper IGCC and the Plant Daniel scrubber project. Future earnings in the near term will depend, in part, upon maintaining and growing sales which is subject to a number of factors. These factors include weather, competition, new energy contracts with other utilities, energy conservation practiced by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in Mississippi Power's service territory. Changes in regional and global economic conditions may impact sales for Mississippi Power as the pace of the economic recovery remains uncertain. The timing and extent of the economic recovery will impact growth and may impact future earnings. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Mississippi Power in Item 7 of the Form 10-K.

Environmental Matters

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

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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) and the EPA's proposed rules regarding the regulation of excess emissions during periods of startup, shutdown, or malfunction (SSM).

On April 29, 2014, the U.S. Supreme Court overturned the U.S. Court of Appeals for the District of Columbia Circuit's August 2012 decision to vacate CSAPR and remanded the case back to the U.S. Court of Appeals for the District of Columbia Circuit for further proceedings. On October 23, 2014, the U.S. Court of Appeals for the District of Columbia Circuit granted the EPA's motion to lift the stay on CSAPR implementation and approved a revised schedule under which the first phase of the rule will go into effect beginning January 1, 2015. The Southern Company system has developed and continually updates a comprehensive environmental compliance strategy to assess compliance obligations associated with current and proposed environmental requirements, including CSAPR. The ultimate financial and unit operational impact of the rule cannot be determined at this time and is dependent on the outcome of further legal proceedings, the manner in which the EPA and the states implement the final rule, and the development of related emissions allowance markets.

On September 17, 2014, the EPA published a supplemental proposal for the SSM rule. The EPA previously entered into a revised settlement agreement requiring the EPA to finalize the proposed rules by May 22, 2015. The proposed rule would require states subject to the rule (including Alabama and Mississippi) to revise their SSM provisions within 18 months after issuance of the final rule. The ultimate impact of the proposed SSM rule will depend on the specific provisions of the final rule, the development and implementation of rules at the state level, and the outcome of any legal challenges and cannot be determined at this time.

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

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

Water Quality

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

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

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On August 15, 2014, the EPA published a final rule establishing standards for reducing effects on fish and other aquatic life caused by new and existing cooling water intake structures at existing power plants and manufacturing facilities, which became effective October 14, 2014. The ultimate outcome of this final rule will depend on the results of additional studies and implementation of the rule by state regulators, but could result in additional capital and operational costs associated with changes to existing intake structures and cooling systems and increased costs associated with the construction of new generating units. The ultimate impact of this rule will depend on the outcome of any legal challenges and cannot be determined at this time.

Global Climate Issues

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

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

On October 28, 2014, the EPA issued a notice of data availability related to the proposed Clean Power Plan, which was not intended to revise the EPA's proposal but to provide the public with an opportunity to consider and comment on technical issues and data related to the guidelines. The Southern Company system expects to file comments with the EPA at or prior to the EPA's December 1, 2014 extended deadline. These comments may include a preliminary estimated cost of complying with the proposed guidelines utilizing one of the EPA's compliance scenarios. These costs could be significant to the utility industry and the Southern Company system. However, the ultimate financial and operational impact of the Clean Power Plan proposed guidelines on the Southern Company system cannot be determined at this time and will be dependent upon numerous factors. These factors include: the structure, timing, and content of the EPA's final guidelines; individual state implementation of these guidelines, including the potential that state implementation plans impose different standards; additional rulemaking activities in response to legal challenges and court decisions; the impact of future changes in generation and emissions-related technology and costs; the impact of future decisions regarding unit retirement and replacement, including the type and amount of any such replacement capacity; and the time periods over which compliance will be required.

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

FERC Matters

See Note 3 to the financial statements of Mississippi Power under "FERC Matters" in Item 8 of the Form 10-K for additional information regarding the authority to defer in a regulatory asset costs related to the retirement or partial retirement of generating units as a result of environmental compliance rules. See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for information regarding Mississippi Power's construction of the Kemper IGCC.

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On March 31, 2014, Mississippi Power reached a settlement agreement with its wholesale customers and filed a request with the FERC for an increase in the Municipal and Rural Associations (MRA) cost-based electric tariff. The settlement agreement, approved by the FERC on May 20, 2014, provides that base rates under the MRA cost-based electric tariff will increase approximately $10.1 million annually, with revised rates effective for services rendered beginning May 1, 2014.

PSC Matters

Energy Efficiency

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

On June 3, 2014, the Mississippi PSC approved Mississippi Power's 2014 Energy Efficiency Quick Start Plan filing, which includes a portfolio of energy efficiency programs. On October 17, 2014, Mississippi Power filed a revised compliance filing, which proposed an increase of $6.7 million in retail revenues for the period December 2014 through December 2015. The Mississippi PSC approved the revised filing on November 4, 2014.

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.

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

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

Environmental Compliance Overview Plan

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

On August 1, 2014, Mississippi Power entered into a settlement agreement with the Sierra Club (Sierra Club Settlement Agreement) that, among other things, requires the Sierra Club to dismiss or withdraw all pending legal and regulatory challenges to the issuance of the CPCN to construct a scrubber on Plant Daniel Units 1 and 2. In addition, and consistent with Mississippi Power's ongoing evaluation of recent environmental rules and regulations, Mississippi Power agreed to retire, repower with natural gas, or convert to an alternative non-fossil fuel source Plant Sweatt Units 1 and 2 (80 MWs) no later than December 2018. Mississippi Power also agreed that it would cease burning coal and other solid fuel at Plant Watson Units 4 and 5 (750 MWs) and begin operating those units solely on natural gas no later than April 2015, and cease burning coal and other solid fuel at Plant Greene County Units 1 and 2 (200 MWs) and begin operating those units solely on natural gas no later than April 2016. On August 4, 2014, Mississippi Power, the Sierra Club, and the Mississippi PSC filed a joint motion to dismiss the appeal related to the CPCN to construct a scrubber on Plant Daniel Units 1 and 2. On August 28, 2014, the Chancery Court dismissed the appeal.

In accordance with a 2011 accounting order from the Mississippi PSC, Mississippi Power has the authority to defer in a regulatory asset for future recovery all plant retirement- or partial retirement-related costs resulting from

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environmental regulations. As of September 30, 2014, $5.5 million of Plant Greene County CWIP had been reclassified as a regulatory asset. Additional costs associated with the remaining net book value of coal-related equipment will be reclassified to a regulatory asset at the time of retirement for Plants Greene County and Watson. Approved regulatory asset costs will be amortized over a period to be determined by the Mississippi PSC. As a result, these decisions are not expected to have a material impact on Mississippi Power's financial statements. See "Other Matters – Sierra Club Settlement Agreement" and Note (B) to the Condensed Financial Statements under "Other Matters – Sierra Club Settlement Agreement" herein for additional information.

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

Fuel Cost Recovery

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

At September 30, 2014, the amount of under recovered retail fuel costs included on Mississippi Power's Condensed Balance Sheet herein was $13.1 million compared to over recovered retail fuel costs of $14.5 million at December 31, 2013.

Ad Valorem Tax Adjustment

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

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

Integrated Coal Gasification Combined Cycle

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" of Mississippi Power in Item 7 and Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K for information regarding Mississippi Power's construction of the Kemper IGCC.

Kemper IGCC Project Approval

In 2012, the Mississippi PSC issued the 2012 MPSC CPCN Order, a detailed order confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing the acquisition, construction, and operation of the Kemper IGCC, which the Sierra Club appealed to the Chancery Court. Later in 2012, the Chancery Court affirmed the 2012 MPSC CPCN Order. In January 2013, the Sierra Club filed an appeal of the Chancery Court's ruling with the Mississippi Supreme Court.

On August 1, 2014, Mississippi Power entered into the Sierra Club Settlement Agreement that, among other things, requires the Sierra Club to dismiss or withdraw all pending legal and regulatory challenges against the Kemper IGCC, including the appeal to the Mississippi Supreme Court related to the 2012 MPSC CPCN. On August 4, 2014, Mississippi Power and the Sierra Club filed a joint motion to dismiss the appeal related to the 2012 MPSC CPCN, which the Mississippi Supreme Court granted on September 11, 2014. See "Other Matters – Sierra Club Settlement Agreement" and Note (B) to the Condensed Financial Statements under "Other Matters – Sierra Club Settlement Agreement" herein for additional information.

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

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pipeline facilities, and AFUDC related to the Kemper IGCC. The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, with recovery of prudently-incurred costs subject to approval by the Mississippi PSC. Exceptions to the $2.88 billion cost cap include the Cost Cap Exceptions, as contemplated in the 2013 Settlement Agreement (defined below) and the 2012 MPSC CPCN Order. Recovery of the Cost Cap Exception amounts remains subject to review and approval by the Mississippi PSC.

The Kemper IGCC was originally projected to be placed in service in May 2014. Mississippi Power placed the combined cycle and the associated common facilities portion of the Kemper IGCC in service on natural gas on August 9, 2014, and continues to focus on completing the remainder of the Kemper IGCC, including the gasifier and the gas clean-up facilities, for which the in-service date is currently expected to occur in the first half of 2016. In accordance with a Mississippi PSC order, on August 18, 2014, Mississippi Power provided an analysis of the costs and benefits of placing the combined cycle and the associated common facilities portion of the Kemper IGCC in service, including the expected accounting treatment. Mississippi Power's analysis requested, among other things, confirmation of Mississippi Power's accounting treatment by the Mississippi PSC of (1) the continued collection of rates as prescribed by the 2013 MPSC Rate Order (defined below), with the current recognition as revenue of the related equity return on all assets placed in service, and the deferral of all remaining rate collections under the 2013 MPSC Rate Order to a regulatory liability account, (2) the continued accrual of AFUDC through the in-service date of the remainder of the Kemper IGCC, and (3) the deferral of operating costs for the combined cycle as regulatory assets. Under Mississippi Power's proposal, non-incremental costs that would have been incurred whether or not the combined cycle was placed in service would be included in a regulatory asset and would continue to be subject to the $2.88 billion cost cap. Additionally, incremental costs that would not have been incurred if the combined cycle had not gone into service would be included in a regulatory asset and would not be subject to the cost cap because these costs are incurred to support operation of the combined cycle. All energy revenues associated with the combined cycle variable operating and maintenance expenses would be credited to this regulatory asset. See "Regulatory Assets and Liabilities" herein for additional information.

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

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

Cost Category	2010 Project Estimate(f)		Current Estimate		Actual Costs at September 30, 2014
	(in billions)
Plant Subject to Cost Cap(a)	$	2.40	$	4.86	$	4.06
Lignite Mine and Equipment	0.21		0.23		0.23
CO2 Pipeline Facilities	0.14		0.11		0.10
AFUDC(b)(c)	0.17		0.62		0.41
Combined Cycle and Related Assets Placed in   Service – Incremental(d)	—		—		—
General Exceptions	0.05		0.10		0.07
Regulatory Asset(c)(e)	—		0.18		0.10
Total Kemper IGCC(a)(c)	$	2.97	$	6.10	$	4.97

(a) The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, net of the DOE Grants and excluding the Cost Cap Exceptions. The Current Estimate and Actual Costs include non-incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service in August 2014 that are subject to the $2.88 billion cost cap.

(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 March 31, 2016.

(d) Incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service on August 9, 2014, net of costs related to energy sales.

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

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

Of the total costs incurred as of September 30, 2014, $2.88 billion was included in property, plant, and equipment (which is net of the DOE Grants and estimated probable losses of $1.98 billion), $104.3 million in other regulatory assets, and $3.9 million in other deferred charges and assets in Mississippi Power's Condensed Balance Sheet herein, and $1.1 million was previously expensed.

Mississippi Power does not intend to seek any rate recovery or joint owner contributions for any related costs that exceed the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions. Mississippi Power recorded pre-tax charges to income for revisions to the cost estimate of $418.0 million ($258.1 million after tax) in the third quarter 2014 and $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 reflected 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. The third quarter 2014 revised cost estimate primarily reflects costs related to the extension of the project schedule for the remainder of the Kemper IGCC (including the gasifier and the gas clean-up facilities) as a result of matters related to the time expected to be required for start-up activities and operational readiness, including enhancing the scope of specialized operator training. The current estimate includes costs through March 31, 2016. Any further extension of the in-service date is currently estimated to result in additional base costs of approximately $20 million to $30 million per month, which includes maintaining necessary levels of start-up labor, materials, and fuel, as well as operational resources required to execute start-up and commissioning activities.

Any further 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

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inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under construction or other agreements, operational performance, operational readiness, including specialized operator training, unforeseen engineering or design problems, start-up activities for this first-of-a-kind technology (including major equipment failure and system integration), and/or operations. In subsequent periods, any further changes in the estimated costs to complete construction and start-up of the Kemper IGCC subject to the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions, will be reflected in Mississippi Power's statements of operations and these changes could be material.

Rate Recovery of Kemper IGCC Costs

The ultimate outcome of the rate recovery matters discussed herein, including the resolution of legal challenges, determinations of prudency, and the specific manner of recovery of prudently-incurred costs, cannot be determined at this time, but could have a material impact on Mississippi Power's results of operations, financial condition, and liquidity.

2012 MPSC CPCN Order

The 2012 MPSC CPCN Order included provisions relating to both Mississippi Power's recovery of financing costs during the course of construction of the Kemper IGCC and Mississippi Power's recovery of costs following the date the Kemper IGCC is placed in service. With respect to recovery of costs following the in-service date of the Kemper IGCC, the 2012 MPSC CPCN Order provided for the establishment of operational cost and revenue parameters based upon assumptions in Mississippi Power's petition for the CPCN. Mississippi Power expects the Mississippi PSC to apply operational parameters in connection with the evaluation of the 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.

2013 Settlement Agreement

In January 2013, Mississippi Power entered into a settlement agreement with the Mississippi PSC that, among other things, establishes the process for resolving matters regarding cost recovery related to the Kemper IGCC and dismissed Mississippi Power's appeal of the 2012 MPSC CWIP Order (2013 Settlement Agreement). Under the 2013 Settlement Agreement, Mississippi Power agreed to limit the portion of prudently-incurred Kemper IGCC costs to be included in retail rate base to the $2.4 billion certificated cost estimate, plus the Cost Cap Exceptions, but excluding AFUDC, and any other costs permitted or determined to be excluded from the $2.88 billion cost cap by the Mississippi PSC. The 2013 Settlement Agreement also allows Mississippi Power to secure alternate financing for costs that are not otherwise recovered in any Mississippi PSC rate proceedings contemplated by the 2013 Settlement Agreement. Legislation to authorize a multi-year rate plan and legislation to provide for alternate financing through securitization of up to $1.0 billion of prudently-incurred costs was enacted into law in February 2013. Mississippi Power intends to securitize (1) prudently-incurred costs in excess of the certificated cost estimate and up to the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions, (2) accrued AFUDC, and (3) other prudently-incurred costs, which include carrying costs from the estimated in-service date until securitization is finalized and other costs not included in the Seven-Year Rate Plan (described below) 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. With the extension of the Kemper IGCC in-service date, under certain potential scenarios, the amount eligible to be securitized may exceed $1.0 billion. In that event, Mississippi Power would expect to pursue rate recovery of any additional eligible costs.

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

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Agreement. Mississippi Power continues to work with the Mississippi PSC and the Mississippi Public Utilities Staff (MPUS) to implement the requirements of the 2013 Settlement Agreement.

2013 MPSC Rate Order

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

In March 2013, the Mississippi PSC issued a 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 (2013 MPSC Rate Order). For the first nine months of 2014, $121.9 million has been collected, with $16.8 million recognized in retail revenues in Mississippi Power's Condensed Statements of Operations herein and the remainder deferred in other regulatory liabilities to be used to mitigate customer rate impacts after the Kemper IGCC is placed in service and included in Mississippi Power's Condensed Balance Sheet herein. Since March 2013, $220.0 million has been collected, with $27.1 million recognized in retail revenues in Mississippi Power's Condensed Statements of Operations herein, and the remainder deferred in other regulatory liabilities to be used to mitigate customer rate impacts after the Kemper IGCC is placed in service and included in Mississippi Power's Condensed Balance Sheet herein.

Because the 2013 MPSC Rate Order did not provide for the inclusion of CWIP in rate base as permitted by the Baseload Act, Mississippi Power continues to record AFUDC on the Kemper IGCC through the in-service date. Mississippi Power will not record AFUDC on any additional costs of the Kemper IGCC that exceed the $2.88 billion cost cap, except for Cost Cap Exception amounts. Mississippi Power will continue to record AFUDC and to comply with the 2013 MPSC Rate Order by collecting and deferring the approved rates through the in-service date 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. An adverse outcome could affect the rates that went into effect on March 19, 2013 and January 1, 2014 and the related amounts deferred as a regulatory liability.

See "Regulatory Assets and Liabilities" herein for additional information.

Seven-Year Rate Plan

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

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

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of 2012 (ATRA), which currently requires that assets be placed in service in 2014. While Mississippi Power placed the combined cycle and the associated common facilities portion of the Kemper IGCC in service on August 9, 2014, extension of the in-service date for the remainder of the Kemper IGCC beyond 2014 results in the loss of tax benefits related to bonus depreciation under current law. The estimated value to retail customers of the bonus depreciation tax benefits not associated with the combined cycle and the associated common facilities portion of the Kemper IGCC is approximately $130 million to $160 million.

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 investment tax credits, various other revenue requirement items, and other tax matters, including bonus depreciation, which include ensuring compliance with the normalization requirements of the Internal Revenue Code. The impact of these revisions for the average annual retail revenue requirement is estimated to be an increase of approximately $60 million to $70 million through 2020. The revision of the Seven-Year Rate Plan is also expected to reflect rate mitigation options identified by Mississippi Power, including Section 174 Research and Experimental (R&E) tax deductions, 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. See "Income Tax Matters" herein for additional information.

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 alternate means, which could include a traditional rate case.

In addition to current estimated costs at September 30, 2014 of $6.10 billion, Mississippi Power anticipates that it will incur additional costs after the Kemper IGCC in-service date until the Seven-Year Rate Plan, as ultimately amended or revised, and securitization are finalized. These costs include, but are not limited to, regulatory costs and additional carrying costs which could be material. Recovery of these costs would be subject to approval by the Mississippi PSC.

Prudence Reviews

The Mississippi PSC's review of Kemper IGCC costs is ongoing. On August 5, 2014, the Mississippi PSC ordered that a consolidated prudence determination of all Kemper IGCC costs be completed after the entire project has been placed in service and has demonstrated availability for a reasonable period of time as determined by the Mississippi PSC and the MPUS. The Mississippi PSC has encouraged the parties to work in good faith to settle contested issues and Mississippi Power is working to reach a mutually acceptable resolution.

Regulatory Assets and Liabilities

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 through the in-service date, subject to review of such costs by the Mississippi PSC. Such costs include, but are not limited to, interest costs on Kemper assets currently placed in service, costs associated with Mississippi PSC and MPUS consultants, prudence costs, legal fees, and operating expenses associated with assets placed in service.

On August 18, 2014, Mississippi Power requested confirmation by the Mississippi PSC of Mississippi Power's authority to defer all operating expenses associated with the operation of the combined cycle subject to review of such costs by the Mississippi PSC. In addition, Mississippi Power is authorized to accrue carrying costs on the unamortized balance of such regulatory assets at a rate and in a manner to be determined by the Mississippi PSC in future cost recovery mechanism proceedings. As of September 30, 2014, the regulatory asset balance associated with the Kemper IGCC was $104.3 million. The projected balance at March 31, 2016 is estimated to total approximately $180 million. 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.

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In March 2013, the Mississippi PSC issued the 2013 MPSC Rate Order approving retail rate increases of 15% effective March 19, 2013, and 3% effective January 1, 2014, which collectively are designed to collect $156 million annually beginning in 2014. Because the 2013 MPSC Rate Order did not provide for the inclusion of CWIP in rate base as permitted by the Baseload Act, Mississippi Power continues to record AFUDC on the Kemper IGCC through the in-service date. To comply with the 2013 MPSC Rate Order, Mississippi Power is deferring the collections under the approved rates through the in-service date in a regulatory liability to be amortized and used to mitigate customer rate impacts after the Kemper IGCC is placed in service. Mississippi Power is accruing interest costs on the unamortized balance of such regulatory liability for the benefit of retail customers. The disposition of the regulatory liability will be determined by the Mississippi PSC in future cost recovery mechanism proceedings.

Lignite Mine and CO₂ Pipeline Facilities

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

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

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

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

Proposed Sale of Undivided Interest to SMEPA

In 2010, Mississippi Power and SMEPA entered into an asset purchase agreement (APA) whereby SMEPA agreed to purchase a 17.5% undivided interest in the Kemper IGCC. In 2012, the Mississippi PSC approved the sale and transfer of the 17.5% undivided interest in the Kemper IGCC to SMEPA. Later in 2012, Mississippi Power and SMEPA signed an amendment to the APA whereby SMEPA reduced its purchase commitment percentage from a 17.5% to a 15% undivided interest in the Kemper IGCC. In March 2013, Mississippi Power and SMEPA signed an amendment to the APA whereby 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.

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

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

The letter agreement also provides for certain post-closing adjustments to address any differences between the actual and the estimated amounts of post-in-service date costs (both expenses and capital) and revenue credits for those portions of the Kemper IGCC previously placed in service. In addition, if the parties approve an amendment to the APA incorporating the terms of the letter agreement but do not execute the amendment before December 31, 2014, the parties agreed to extend the current APA through December 31, 2015.

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

On October 9, 2014, Mississippi Power received an additional $50 million deposit from SMEPA to be applied to the purchase.

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

Income Tax Matters

See Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information about the Kemper IGCC. The ultimate outcome of these tax matters cannot be determined at this time.

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 will apply primarily to the combined cycle and associated common facilities portion of the Kemper IGCC that were placed in service on August 9, 2014. The estimated cash flow benefit is approximately $100 million.

Investment Tax Credits

The IRS allocated $279 million (Phase II) of Internal Revenue Code Section 48A tax credits to Mississippi Power in connection with the Kemper IGCC. Through September 30, 2014, Mississippi Power had recorded tax benefits

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totaling $276.4 million for the Phase II credits, of which approximately $140 million have been utilized through that date. These credits will be amortized as a reduction to depreciation and amortization over the life of the Kemper IGCC and are dependent upon meeting the IRS certification requirements, including an in-service date no later than April 19, 2016 and the capture and sequestration (via enhanced oil recovery) of at least 65%of the CO₂ produced by the Kemper IGCC during operations in accordance with the Internal Revenue Code. 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.

Section 174 Research and Experimental Deduction

For the 2013 tax year, Southern Company included in its consolidated federal income tax return a deduction for R&E expenditures related to the Kemper IGCC. Due to the uncertainty related to this tax position, Mississippi Power recorded an unrecognized tax benefit of approximately $100 million as of September 30, 2014. See Note (G) to the Condensed Financial Statements under "Unrecognized Tax Benefits" herein for additional information.

Other Matters

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

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

Sierra Club Settlement Agreement

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

Under the Sierra Club Settlement Agreement, Mississippi Power agreed to, among other things, fund a $15 million grant payable over a 15-year period for an energy efficiency and renewable program and contribute $2 million to a conservation fund. In accordance with the Sierra Club Settlement Agreement, Mississippi Power paid $7 million in the third quarter 2014, recognized in other income (expense), net in Mississippi Power's Condensed Statements of Operations herein. In addition, and consistent with Mississippi Power's ongoing evaluation of recent environmental rules and regulations, Mississippi Power agreed to retire, repower with natural gas, or convert to an alternative non-fossil fuel source Plant Sweatt Units 1 and 2 (80 MWs) no later than December 2018. Mississippi Power also

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agreed that it would cease burning coal and other solid fuel at Plant Watson Units 4 and 5 (750 MWs) and begin operating those units solely on natural gas no later than April 2015, and cease burning coal and other solid fuel at Plant Greene County Units 1 and 2 (200 MWs) and begin operating those units solely on natural gas no later than April 2016. See "PSC Matters – Environmental Compliance Overview Plan" herein for additional information.

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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

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

During 2014, Mississippi Power further extended the scheduled in-service date for the Kemper IGCC to the first half of 2016 and revised its cost estimate to complete construction and start-up of the Kemper IGCC to an amount that exceeds the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions. Mississippi Power does not intend to seek any rate recovery or any joint owner contributions for any related costs that exceed the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions.

As a result of the revisions to the cost estimate, Mississippi Power recorded total pre-tax charges to income for the estimated probable losses on the Kemper IGCC of $418.0 million ($258.1 million after tax) in the third quarter 2014, $380.0 million ($234.7 million after tax) in the first quarter 2014, $40.0 million ($24.7 million after tax) in the fourth quarter 2013, $150.0 million ($92.6 million after tax) in the third quarter 2013, $450.0 million ($277.9 million after tax) in the second quarter 2013, $462.0 million ($285.3 million after tax) in the first quarter 2013, and $78.0 million ($48.2 million after tax) in the fourth quarter 2012. In the aggregate, Mississippi Power has incurred charges of $1.98 billion ($1.22 billion after tax) as a result of changes in the cost estimate for the Kemper IGCC through September 30, 2014.

Mississippi Power has experienced, and may continue to experience, material changes in the cost estimate for the Kemper IGCC. In subsequent periods, any further changes in the estimated costs to complete construction and start-up of the Kemper IGCC subject to the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions will be reflected in Mississippi Power's statements of operations and these changes could be material. Any further cost increases and/or extensions of the in-service date with respect to the Kemper IGCC may result from factors including, but not limited to, labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under construction or other agreements, operational performance, operational readiness, including specialized operator training, unforeseen engineering or design problems, start-up activities for this first-of-a-kind technology (including major equipment failure and system integration), and/or operations.

Mississippi Power's revised cost estimate includes costs through March 31, 2016. Any further extension of the in-service date is currently estimated to result in additional base costs of approximately $20 million to $30 million per month, which includes maintaining necessary levels of start-up labor, materials, and fuel, as well as operational resources required to execute start-up and commissioning activities.

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

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

Recently Issued Accounting Standards

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

FINANCIAL CONDITION AND LIQUIDITY

Overview

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Mississippi Power in Item 7 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" herein for additional information. Earnings for the nine months ended September 30, 2014 were negatively affected by revisions to the cost estimate for the Kemper IGCC; however, Mississippi Power's financial condition remained stable at September 30, 2014 as a result of capital contributions to Mississippi Power by Southern Company.

Through September 30, 2014, Mississippi Power has incurred non-recoverable cash expenditures of $1.18 billion and is expected to incur approximately $0.8 billion in additional non-recoverable cash expenditures through completion of the Kemper IGCC.

During the first nine months of 2014, Mississippi Power received $310.0 million in equity contributions and a $220.0 million loan from Southern Company which was repaid on September 29, 2014. In October 2014, Mississippi Power received an additional $100 million in equity contributions from Southern Company. Mississippi Power intends to continue to monitor its access to short-term and long-term capital markets and bank credit arrangements. Management intends to utilize equity contributions and/or loans from Southern Company and cash, as well as commercial paper, lines of credit, and bank notes as market conditions permit, to fund Mississippi Power's capital needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.

Net cash provided from operating activities totaled $504.7 million for the first nine months of 2014, an increase of $218.0 million as compared to the corresponding period in 2013. The increase in cash provided from operating activities is primarily due to Kemper IGCC collections that are being deferred for future rate mitigation, a decrease in receivables, and increases in accounts payable and accrued compensation, partially offset by investment tax credits related to the Kemper IGCC, income taxes primarily related to the Kemper IGCC, lower fuel inventory additions compared to the prior year, and an increase in under-recovered regulatory clause revenue. Net cash used for investing activities totaled $1.0 billion for the first nine months of 2014 primarily due to gross property additions related to the Kemper IGCC and the Plant Daniel scrubber project. Net cash provided from financing activities totaled $490.1 million for the first nine months of 2014 primarily due to an increase in equity contributions, the issuance of bank notes, and the receipt of an additional SMEPA deposit, partially offset by a return of paid in capital. Fluctuations in cash flow from financing activities vary from period to period based on capital needs and the maturity or redemption of securities. See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs," " – Regulatory Assets and Liabilities," and " – Proposed Sale of Undivided Interest to SMEPA" herein for additional information.

Significant balance sheet changes for the first nine months of 2014 include an increase in securities due within one year of $798.0 million and a decrease in long-term debt of $533.7 million, primarily due to bank loans maturing by the end of the third quarter 2015, as well as an increase in the interest-bearing refundable deposit from SMEPA of

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$75 million. See "Sources of Capital" herein for additional information. Total property, plant, and equipment increased $212.4 million, other regulatory asset, deferred increased $54.8 million, and other regulatory liabilities, deferred increased $122.7 million primarily due to the Kemper IGCC. Additional changes included an increase in prepaid income taxes of $128.0 million, an increase in accrued income taxes of $86.4 million, and an increase in deferred charges related to income taxes of $57.4 million primarily related to R&E tax deductions and investment tax credits related to the Kemper IGCC. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters" herein for additional information. Total common stockholder's equity decreased $155.5 million primarily due to the estimated probable loss on the Kemper IGCC partially offset by the receipt of $310.0 million in capital contributions from Southern Company.

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 $812 million will be required through September 30, 2015 to fund maturities of long-term debt.

The construction program of Mississippi Power is currently estimated to be $1.5 billion for 2014, $804 million for 2015, and $324 million for 2016, which includes expenditures related to the construction and start-up of the Kemper IGCC of $1.3 billion for 2014, $551 million for 2015, and $75 million for 2016. 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 $569 million (including construction costs for all prior periods relating to its proposed ownership interest).

The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; storm impacts; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing units, to meet regulatory requirements; changes in FERC rules and regulations; Mississippi PSC approvals; changes in the expected environmental compliance program; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" herein for additional information and further risks related to the estimated schedule and costs and rate recovery for the Kemper IGCC.

Sources of Capital

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

Mississippi Power has received $245.3 million of DOE Grants that were used for the construction of the Kemper IGCC. An additional $25 million of DOE Grants is expected to be received for commercial operation of the Kemper IGCC. In addition, see Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for information regarding legislation related to the securitization of certain costs of the Kemper IGCC.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Mississippi Power's current liabilities exceeded current assets by approximately $1 billion at September 30, 2014, primarily because of securities due within one year. Management intends to utilize equity contributions and/or loans from Southern Company and cash, as well as commercial paper, lines of credit, and bank notes as market conditions permit, to fund Mississippi Power's capital needs.

At September 30, 2014, Mississippi Power had approximately $89.9 million of cash and cash equivalents. Committed credit arrangements with banks at September 30, 2014 were as follows:

Expires(a)										Executable Term Loans				Due Within One Year
2014		2015		2016		Total		Unused		One Year		Two Years		Term Out		No Term Out
(in millions)						(in millions)				(in millions)				(in millions)
$	15	$	120	$	165	$	300	$	300	$	25	$	40	$	65	$	70

(a) No credit arrangements expire in 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 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 September 30, 2014 was approximately $40.1 million.

Mississippi Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Mississippi Power and the other traditional operating companies. Proceeds from such issuances for the benefit of Mississippi Power are loaned directly to Mississippi Power. The obligations of each company under these arrangements are several and there is no cross-affiliate credit support.

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

Credit Rating Risk

Mississippi Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to below BBB- and/or Baa3. These contracts are for physical electricity sales, fuel transportation and storage, and energy price risk management. At September 30, 2014, the maximum potential collateral requirements under these contracts at a rating below BBB- and/or Baa3 were approximately $259 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.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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, January 2014, and subsequent to September 30, 2014, Mississippi Power received $150 million, $75 million, and $50 million, respectively, of interest-bearing refundable deposits from SMEPA to be applied to the sale price for the pending sale of an undivided interest in the Kemper IGCC. Until the sale is closed, the deposits bear interest at Mississippi Power's AFUDC rate adjusted for income taxes, which was 10.132% per annum for the period ended September 30, 2014 and 9.932% per annum for 2013, and are refundable to SMEPA upon termination of the asset purchase agreement related to such purchase or within 15 days of a request by SMEPA for a full or partial refund. In July 2013, Southern Company entered into an agreement with SMEPA under which Southern Company has agreed to guarantee the obligations of Mississippi Power with respect to any required refund of the deposits.

In May 2014, Mississippi Power issued a 19-month floating rate promissory note to Southern Company for a loan bearing interest based on one-month LIBOR. This loan was for $220 million aggregate principal amount and the proceeds were used for working capital and other general corporate purposes, including Mississippi Power's construction program. This loan was repaid on September 29, 2014.

In May 2014 and August 2014, the Mississippi Business Finance Corporation (MBFC) issued $12.3 million and $10.5 million, respectively, aggregate principal amount of MBFC Taxable Revenue Bonds (Mississippi Power Company Project), Series 2013A for the benefit of Mississippi Power and proceeds were used to reimburse Mississippi Power for the cost of the acquisition, construction, equipping, installation, and improvement of certain equipment and facilities for the lignite mining facility related to the Kemper IGCC. Any future issuances of the Series 2013A bonds will be used for this same purpose. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Financing Activities" of Mississippi Power in Item 7 of the Form 10-K for additional information.

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

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AND SUBSIDIARY COMPANIES

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CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2014			2013			2014			2013
	(in thousands)						(in thousands)
Operating Revenues:
Wholesale revenues, non-affiliates	$	331,878		$	265,752		$	870,093		$	705,828
Wholesale revenues, affiliates	102,631			96,795			242,527			263,624
Other revenues	747			2,220			2,293			5,517
Total operating revenues	435,256			364,767			1,114,913			974,969
Operating Expenses:
Fuel	178,281			133,464			420,896			363,466
Purchased power, non-affiliates	28,156			19,673			72,643			56,553
Purchased power, affiliates	12,796			7,011			58,475			21,158
Other operations and maintenance	46,347			41,309			168,392			154,920
Depreciation and amortization	59,508			41,094			162,524			126,152
Taxes other than income taxes	5,458			5,719			16,842			16,526
Total operating expenses	330,546			248,270			899,772			738,775
Operating Income	104,710			116,497			215,141			236,194
Other Income and (Expense):
Interest expense, net of amounts capitalized	(22,983		)	(12,961		)	(66,952		)	(53,923		)
Other income (expense), net	5,511			(791		)	5,596			(2,739		)
Total other income and (expense)	(17,472		)	(13,752		)	(61,356		)	(56,662		)
Earnings Before Income Taxes	87,238			102,745			153,785			179,532
Income taxes	21,960			17,592			22,177			37,265
Net Income	65,278			85,153			131,608			142,267
Less: Net income attributable to noncontrolling interest	1,647			—			3,694			—
Net Income Attributable to Southern Power Company	$	63,631		$	85,153		$	127,914		$	142,267

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended September 30,					For the Nine Months Ended September 30,
	2014			2013		2014			2013
	(in thousands)					(in thousands)
Net Income	$	65,278		$	85,153	$	131,608		$	142,267
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(1), $-, $(1) and $-, respectively	(1		)	—		(1		)	—
Reclassification adjustment for amounts included in net income, net of tax of $52, $213, $115 and $2,310 respectively	84			338		281			3,619
Total other comprehensive income (loss)	83			338		280			3,619
Less: Comprehensive income attributable to noncontrolling interest	1,647			—		3,694			—
Comprehensive Income Attributable to Southern Power Company	$	63,714		$	85,491	$	128,194		$	145,886

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 Nine Months Ended September 30,
	2014			2013
	(in thousands)
Operating Activities:
Net income	$	131,608		$	142,267
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	158,264			131,955
Deferred income taxes	(6,340		)	83,331
Investment tax credits	38,215			(25,137		)
Deferred revenues	(2,452		)	3,136
Other, net	3,853			962
Changes in certain current assets and liabilities —
-Receivables	(62,757		)	(28,486		)
-Fossil fuel stock	(1,565		)	881
-Materials and supplies	(3,455		)	(5,902		)
-Prepaid income taxes	38,716			(12,485		)
-Other current assets	(720		)	(2,017		)
-Accounts payable	26,989			(4,282		)
-Accrued taxes	62,124			12,550
-Accrued interest	(13,451		)	(8,306		)
-Other current liabilities	2,000			235
Net cash provided from operating activities	371,029			288,702
Investing Activities:
Plant acquisition	(217,547		)	(111,600		)
Property additions	(14,782		)	(463,873		)
Change in construction payables	(3,282		)	292
Payments pursuant to long-term service agreements	(41,782		)	(40,978		)
Investment in restricted cash	(166		)	(20,000		)
Other investing activities	(9,996		)	(1,724		)
Net cash used for investing activities	(287,555		)	(637,883		)
Financing Activities:
Increase in notes payable, net	19,995			120,798
Proceeds —
Senior notes	—			300,000
Capital contributions	(3,628		)	1,897
Other long-term debt	10,199			22,722
Repayments — Other long-term debt	(818		)	(220		)
Distributions to noncontrolling interest	(150		)	(146		)
Contributions from noncontrolling interest	7,492			16,802
Payment of common stock dividends	(98,340		)	(96,840		)
Other financing activities	(184		)	(2,287		)
Net cash provided from (used for) financing activities	(65,434		)	362,726
Net Change in Cash and Cash Equivalents	18,040			13,545
Cash and Cash Equivalents at Beginning of Period	68,744			28,592
Cash and Cash Equivalents at End of Period	$	86,784		$	42,137
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $(113) and $7,682 capitalized for 2014 and 2013, respectively)	$	78,496		$	55,190
Income taxes, net	(91,193		)	(6,518		)
Noncash transactions — accrued property additions at end of period	549			36,370

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 September 30, 2014		At December 31, 2013
	(in thousands)
Current Assets:
Cash and cash equivalents	$	86,784	$	68,744
Receivables —
Customer accounts receivable	103,740		73,497
Other accounts receivable	9,107		3,983
Affiliated companies	46,089		38,391
Fossil fuel stock, at average cost	20,743		19,178
Materials and supplies, at average cost	58,234		54,780
Prepaid service agreements — current	30,996		81,206
Prepaid income taxes	47,374		54,732
Other prepaid expenses	8,518		7,915
Assets from risk management activities	810		182
Total current assets	412,395		402,608
Property, Plant, and Equipment:
In service	4,941,745		4,696,134
Less accumulated provision for depreciation	981,568		871,963
Plant in service, net of depreciation	3,960,177		3,824,171
Construction work in progress	11,329		9,843
Total property, plant, and equipment	3,971,506		3,834,014
Other Property and Investments:
Goodwill	1,839		1,839
Other intangible assets, net of amortization of $7,583 and $5,614 at September 30, 2014 and December 31, 2013, respectively	47,787		43,505
Total other property and investments	49,626		45,344
Deferred Charges and Other Assets:
Prepaid long-term service agreements	83,403		73,676
Other deferred charges and assets — affiliated	2,556		4,605
Other deferred charges and assets — non-affiliated	89,097		68,853
Total deferred charges and other assets	175,056		147,134
Total Assets	$	4,608,583	$	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 September 30, 2014		At December 31, 2013
	(in thousands)
Current Liabilities:
Securities due within one year	$	531,184	$	599
Notes payable	19,995		—
Accounts payable —
Affiliated	89,853		56,661
Other	11,842		20,747
Accrued taxes —
Accrued income taxes	8,939		161
Other accrued taxes	13,115		2,662
Accrued interest	14,901		28,352
Other current liabilities	6,549		18,492
Total current liabilities	696,378		127,674
Long-term Debt	1,098,078		1,619,241
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	749,528		724,390
Accumulated deferred investment tax credits	396,020		340,269
Deferred capacity revenues — affiliated	26,989		15,279
Other deferred credits and liabilities — affiliated	858		1,621
Other deferred credits and liabilities — non-affiliated	10,740		7,896
Total deferred credits and other liabilities	1,184,135		1,089,455
Total Liabilities	2,978,591		2,836,370
Redeemable Noncontrolling Interest	39,813		28,778
Common Stockholder's Equity:
Common stock, par value $.01 per share —
Authorized — 1,000,000 shares
Outstanding — 1,000 shares	—		—
Paid-in capital	1,025,407		1,029,035
Retained earnings	561,573		531,998
Accumulated other comprehensive income	3,199		2,919
Total common stockholder's equity	1,590,179		1,563,952
Total Liabilities and Stockholder's Equity	$	4,608,583	$	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

THIRD QUARTER 2014 vs. THIRD QUARTER 2013

AND

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

OVERVIEW

Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Power continually seeks opportunities to execute its strategy to create value through various transactions including acquisitions and sales of assets, construction of new power plants, and entry into PPAs primarily with investor owned utilities, independent power producers, municipalities, and electric cooperatives. In general, Southern Power has constructed or acquired new generating capacity only after entering into long-term PPAs for the new facilities.

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) and Macho Springs Solar, LLC (Macho Springs) on April 17, 2014 and May 22, 2014, respectively. The two solar facilities began commercial operation in May 2014 with the approximate 20-MW Adobe solar photovoltaic facility serving a PPA with Southern California Edison (SCE) through 2034 and the approximate 50-MW Macho Springs solar photovoltaic facility serving a PPA with El Paso Electric Company (EPE) also through 2034.

Subsequent to September 30, 2014, Southern Power, through its wholly-owned subsidiary SG2 Holdings, LLC (Holdings), acquired all of the outstanding membership interests of SG2 Imperial Valley, LLC (SG2) from a wholly-owned subsidiary of First Solar, Inc. (First Solar), the developer of the project. SG2 is constructing an approximately 150-MW solar photovoltaic facility in Southern California (Imperial Facility), which is expected to begin commercial operation later in the fourth quarter 2014. Prior to commercial operation, subject to certain terms and conditions, including the payment of additional agreed upon capital contributions, First Solar will become a non-controlling minority member of Holdings. The Imperial Facility's output is contracted under a 25-year PPA with San Diego Gas & Electric Company, a subsidiary of Sempra Energy.

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

RESULTS OF OPERATIONS

Net Income

Third Quarter 2014 vs. Third Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$(21.6)	(25.3)	$(14.4)	(10.1)

Net income attributable to Southern Power for the third quarter 2014 was $63.6 million compared to $85.2 million for the corresponding period in 2013. The decrease was primarily due to an increase in depreciation, lower capitalized interest due to reduced construction, and lower ITCs in income taxes, partially offset by an increase in energy revenue from non-affiliates primarily due to increased revenue from new solar contracts.

Net income for year-to-date 2014 was $127.9 million compared to $142.3 million for the corresponding period in 2013. The decrease was primarily due to a decrease in capacity revenues, increased depreciation arising from new

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solar facilities, lower ITCs in income taxes, and lower capitalized interest due to reduced construction. The decrease was partially offset by an increase in energy revenue from non-affiliates primarily from new solar contracts and beneficial changes in certain state income taxes.

Wholesale Revenues–Non-Affiliates

Third Quarter 2014 vs. Third Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$66.1	24.9	$164.3	23.3

Wholesale revenues from sales to non-affiliates will vary depending on the energy demand of those customers and their generation capacity, as well as the market prices of wholesale energy compared to the cost of Southern Power's energy. Increases and decreases in revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income.

Details of the changes in wholesale revenues from non-affiliates were as follows:

	Third Quarter  2014					Year-to-Date 2014
	(in millions)			(% change)		(in millions)			(% change)
Wholesale Revenues – Non-Affiliates, prior year	$	265.8				$	705.8
Change resulting from -
Capacity	(4.4		)	(1.6	)	(10.0		)	(1.4	)
Energy – solar	20.0			7.5		60.3			8.5
Energy – other	50.5			19.0		114.0			16.2
Wholesale Revenues – Non-Affiliates, current year	$	331.9		24.9	%	$	870.1		23.3	%

The increase in energy – solar was primarily a result of new solar PPAs. The increase in energy – other, primarily from gas plants, arose from requirements contracts, increased revenue from existing contracts, and energy sales not under PPAs, primarily as a result of higher demand. The increases were offset by a decrease in capacity revenues primarily as a result of periodic scheduled adjustments to requirements contracts. The increase in energy sales reflects a 4.6% and 16.9% increase in the average price of energy and a 47.0% and 26.8% increase in KWH sales for the third quarter and year-to-date 2014, respectively.

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

Third Quarter 2014 vs. Third Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$5.8	6.0	$(21.1)	(8.0)

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 third quarter 2014 were $102.6 million compared to $96.8 million for the corresponding period in 2013. The increase was the result of a $9.3 million increase in energy revenue, primarily due to an increase in energy sales under the IIC, reflecting a 13.2% increase in the average price of energy, primarily as a result of higher natural gas prices. This increase was partially offset by a $3.5 million decrease in capacity revenue as a result of the completion of an existing contract for Plant Dahlberg.

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Wholesale revenues from affiliates for year-to-date 2014 were $242.5 million compared to $263.6 million for the corresponding period in 2013. The decrease was the result of a decrease in energy revenue, primarily due to a $24.2 million decrease in energy sales under the IIC, reflecting a 25.2% decrease in KWH sales, primarily as a result of higher natural gas prices and the availability of lower cost affiliate power. Also contributing to the decrease was a $4.6 million decrease in capacity revenue as a result of the completion of an existing contract for Plant Dahlberg. The decrease was partially offset by a $7.7 million increase in energy revenues under existing contracts, reflecting a 21.7% increase in the average price of energy and a 14.2% increase in KWH sales, primarily as a result of higher natural gas prices and increased demand.

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

	Third Quarter 2014 vs. Third Quarter 2013			Year-to-Date 2014 vs. Year-to-Date 2013
	(change in millions)		(% change)	(change in millions)		(% change)
Fuel	$	44.9	33.6	$	57.4	15.8
Purchased power – non-affiliates	8.4		42.9	16.1		28.6
Purchased power – affiliates	5.8		82.8	37.3		175.8
Total fuel and purchased power expenses	$	59.1		$	110.8

Southern Power PPAs for natural gas-fired generation generally provide that the purchasers are responsible for substantially all of the cost of fuel. Consequently, any increase or decrease in fuel cost is generally accompanied by an increase or decrease in related fuel revenue and does not have a significant impact on net income. Southern Power is responsible for the cost of fuel for generating units that are not covered under PPAs. Power from these generating units is sold into the market or sold to affiliates under the IIC.

Purchased power expenses will vary depending on demand and the availability and cost of generating resources throughout the Southern Company system and other contract resources. Load requirements are submitted to the power pool on an hourly basis and are fulfilled with the lowest cost alternative, whether that is generation owned by Southern Power Company, affiliate-owned generation, or external purchases.

In the third quarter 2014, total fuel and purchased power expenses were $219.2 million compared to $160.1 million for the corresponding period in 2013. Fuel and purchased power expenses increased $59.1 million reflecting a 13.7% increase in the average cost of natural gas and a 14.2% increase in the average cost of purchased power primarily as a result of higher natural gas prices and the availability of lower cost affiliate power. This increase also reflects a 19.1% increase in the volume of KWHs purchased and generated primarily as a result of higher demand.

For year-to-date 2014, total fuel and purchased power expenses were $552.0 million compared to $441.2 million for the corresponding period in 2013. Fuel and purchased power expenses increased $110.8 million reflecting a 24.2% increase in the average cost of natural gas and a 20.1% increase in the average cost of purchased power primarily as a result of higher natural gas prices and the availability of lower cost affiliate power.

Fuel

In the third quarter 2014, fuel expense was $178.3 million compared to $133.4 million for the corresponding period in 2013. The increase was due to a $22.5 million increase associated with the higher average cost of fuel per KWH generated primarily due to higher average natural gas prices and a $22.4 million increase associated with the volume of KWHs generated primarily due to higher demand.

For year-to-date 2014, fuel expense was $420.9 million compared to $363.5 million for the corresponding period in 2013. The increase was due to a $79.1 million increase associated with the higher average cost of fuel per KWH

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generated primarily due to higher average natural gas prices, partially offset by a $21.7 million decrease associated with the volume of KWHs generated primarily as a result of the availability of lower cost affiliate power.

Purchased Power

In the third quarter 2014, purchased power expense was $40.9 million compared to $26.7 million for the corresponding period in 2013. The increase was due to a $9.1 million increase associated with the volume of KWHs purchased due to the availability of lower cost affiliate power and a $5.1 million increase associated with the average cost of purchased power, primarily as a result of higher natural gas prices.

For year-to-date 2014, purchased power expense was $131.1 million compared to $77.7 million for the corresponding period in 2013. The increase was due to a $31.5 million increase associated with the volume of KWHs purchased due to the availability of lower cost affiliate power and a $21.9 million increase associated with the average cost of purchased power, primarily as a result of higher natural gas prices.

Other Operations and Maintenance Expenses

Third Quarter 2014 vs. Third Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$5.0	12.2	$13.5	8.7

In the third quarter 2014, other operations and maintenance expenses were $46.3 million compared to $41.3 million for the corresponding period in 2013. For year-to-date 2014, other operations and maintenance expenses were $168.4 million compared to $154.9 million for the corresponding period in 2013. The increases were primarily due to scheduled outage and maintenance related costs and increases in labor costs, as well as costs associated with the new solar plants.

Depreciation and Amortization

Third Quarter 2014 vs. Third Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$18.4	44.8	$36.3	28.8

In the third quarter 2014, depreciation and amortization was $59.5 million compared to $41.1 million for the corresponding period in 2013. For year-to-date 2014, depreciation and amortization was $162.5 million compared to $126.2 million for the corresponding period in 2013. The increases were primarily due to an increase in depreciation expense related to solar facilities being placed in service in 2013 and 2014 and additional component depreciation as a result of production being greater during the summer months.

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

Interest Expense, Net of Amounts Capitalized

Third Quarter 2014 vs. Third Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$10.0	77.3	$13.0	24.2

In the third quarter 2014, interest expense, net of amounts capitalized was $23.0 million compared to $13.0 million for the corresponding period in 2013. For year-to-date 2014, interest expense, net of amounts capitalized was $66.9 million compared to $53.9 million for the corresponding period in 2013. The increases were primarily due to a decrease in capitalized interest due to reduced construction activities in 2014 and the issuance of senior notes in July 2013.

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Other Income (Expense), Net

Third Quarter 2014 vs. Third Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$6.3	N/M	$8.3	N/M

N/M – Not meaningful

In the third quarter 2014, other income (expense), net was $5.5 million compared to $(0.8) million for the corresponding period in 2013. For year-to-date 2014, other income (expense), net was $5.6 million compared to $(2.7) million for the corresponding period in 2013. The increases were primarily due to the recognition of a bargain purchase gain arising from a solar acquisition.

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

Income Taxes

Third Quarter 2014 vs. Third Quarter 2013		Year-to-Date 2014 vs. Year-to-Date 2013
(change in millions)	(% change)	(change in millions)	(% change)
$4.4	24.8	$(15.1)	(40.5)

In the third quarter 2014, income taxes were $22.0 million compared to $17.6 million for the corresponding period in 2013. The increase was primarily due to lower ITC-related items and state apportionment changes, partially offset by lower pretax income and an increase in state income tax credits.

For year-to-date 2014, income taxes were $22.2 million compared to $37.3 million for the corresponding period in 2013. The decrease was primarily due to lower pretax income, the impact of state apportionment changes reducing Southern Power's deferred tax liabilities resulting from the addition of new plants placed in service in 2014 and 2013, a change to the income tax filing method for North Carolina, an increase in state income tax credits, and beneficial changes in certain state income tax laws partially offset by lower ITC-related items.

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

FUTURE EARNINGS POTENTIAL

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

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

Environmental Matters

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Southern Power in Item 7 of the Form 10-K for information on the development by federal and state environmental regulatory agencies of additional control strategies for emissions of air pollution from industrial sources, including electric generating facilities. Compliance with possible additional federal or state legislation or regulations related to global climate change, air quality, water quality, or other environmental and health concerns could also significantly affect Southern Power. While Southern Power's PPAs generally contain provisions that

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permit charging the counterparty with some of the new costs incurred as a result of changes in environmental laws and regulations, the full impact of any such regulatory or legislative changes cannot be determined at this time.

Environmental Statutes and Regulations

Air Quality

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

On April 29, 2014, the U.S. Supreme Court overturned the U.S. Court of Appeals for the District of Columbia Circuit's August 2012 decision to vacate CSAPR and remanded the case back to the U.S. Court of Appeals for the District of Columbia Circuit for further proceedings. On October 23, 2014, the U.S. Court of Appeals for the District of Columbia Circuit granted the EPA's motion to lift the stay on CSAPR implementation and approved a revised schedule under which the first phase of the rule will go into effect beginning January 1, 2015. The Southern Company system has developed and continually updates a comprehensive environmental compliance strategy to assess compliance obligations associated with current and proposed environmental requirements, including CSAPR. The ultimate financial and unit operational impact of the rule cannot be determined at this time and is dependent on the outcome of further legal proceedings, the manner in which the EPA and the states implement the final rule, and the development of related emissions allowance markets.

On September 17, 2014, the EPA published a supplemental proposal for the SSM rule. The EPA previously entered into a revised settlement agreement requiring the EPA to finalize the proposed rules by May 22, 2015. The proposed rule would require states subject to the rule (including Alabama, Florida, Georgia, and North Carolina) to revise their SSM provisions within 18 months after issuance of the final rule. The ultimate impact of the proposed SSM rule will depend on the specific provisions of the final rule, the development and implementation of rules at the state level, and the outcome of any legal challenges and cannot be determined at this time.

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

Water Quality

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

On August 15, 2014, the EPA published a final rule establishing standards for reducing effects on fish and other aquatic life caused by new and existing cooling water intake structures at existing power plants and manufacturing facilities, which became effective October 14, 2014. The ultimate outcome of this final rule will depend on the results of additional studies and implementation of the rule by state regulators, but could result in additional capital and operational costs associated with changes to existing intake structures and cooling systems and increased costs associated with the construction of new generating units. The ultimate impact of this rule will depend on the outcome of any legal challenges and cannot be determined at this time.

Global Climate Issues

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

On June 18, 2014, the EPA published the proposed Clean Power Plan, setting forth guidelines for states to develop plans to address CO₂ emissions from existing fossil fuel-fired electric generating units. The EPA's proposed guidelines establish state-specific interim and final CO₂ emission rate goals to be achieved between 2020 and 2029 and in 2030 and thereafter. The EPA also published proposed CO₂ performance standards for modified and

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reconstructed fossil fuel-fired electric generating units. The proposed guidelines and standards could result in operational restrictions and material compliance costs. Also, additional compliance costs could affect results of operations, cash flows, and financial condition if such costs are not recovered through market-based contracts.

On October 28, 2014, the EPA issued a notice of data availability related to the proposed Clean Power Plan, which was not intended to revise the EPA's proposal but to provide the public with an opportunity to consider and comment on technical issues and data related to the guidelines. The Southern Company system expects to file comments with the EPA at or prior to the EPA's December 1, 2014 extended deadline. These comments may include a preliminary estimated cost of complying with the proposed guidelines utilizing one of the EPA's compliance scenarios. These costs could be significant to the utility industry and the Southern Company system. However, the ultimate financial and operational impact of the Clean Power Plan proposed guidelines on the Southern Company system cannot be determined at this time and will be dependent upon numerous factors. These factors include: the structure, timing, and content of the EPA's final guidelines; individual state implementation of these guidelines, including the potential that state implementation plans impose different standards; additional rulemaking activities in response to legal challenges and court decisions; the impact of future changes in generation and emissions-related technology and costs; and the time periods over which compliance will be required.

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

Acquisitions

Adobe Solar, LLC

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

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

Macho Springs Solar, LLC

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

SG2 Imperial Valley, LLC

Subsequent to September 30, 2014, Southern Power, through its wholly-owned subsidiary Holdings, acquired all of the outstanding membership interests of SG2 from a wholly-owned subsidiary of First Solar, the developer of the project. SG2 is constructing the Imperial Facility, an approximately 150-MW solar photovoltaic facility in Southern California, which is expected to begin commercial operation later in the fourth quarter 2014. The Imperial Facility's output is contracted under a 25-year PPA with San Diego Gas & Electric Company, a subsidiary of Sempra Energy.

In connection with this acquisition, Holdings made an aggregate payment (consisting of cash consideration and a secured promissory note) of approximately $128 million to the subsidiary of First Solar and became obligated to pay the contract price as it becomes due under the construction contract for the Imperial Facility. In addition, subject to certain terms and conditions, a subsidiary of First Solar will be admitted as a minority member of Holdings, and

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subsidiaries of each of Southern Power and First Solar, as members of Holdings, will make capital contributions to Holdings that will be used to pay off the previously issued secured promissory note and to fund the Imperial Facility's construction costs. As a result of these capital contributions, the aggregate purchase price payable by Southern Power for the acquisition is approximately $508 million. Following these capital contributions, Southern Power will indirectly own 100% of the class A membership interests of Holdings and be entitled to 51% of all cash distributions from Holdings, and First Solar will indirectly own 100% of the class B membership interests of Holdings and be entitled to 49% of all cash distributions from Holdings. In addition, Southern Power will be entitled to substantially all of the federal tax benefits with respect to this transaction.

If the Imperial Facility does not achieve substantial completion by a certain date, Southern Power may require that First Solar make a rescission payment to Southern Power in an amount equal to Southern Power's investment in Holdings, and Southern Power would be required to transfer its ownership interests in SG2 back to First Solar.

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

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

Power Sales Agreements

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

Southern Power has assumed or entered into additional PPAs during the past nine months primarily in connection with its acquisitions of solar facilities. The coverage ratio of its available capacity for the next five years and the next 10 years has not changed materially as of September 30, 2014 from the period ended December 31, 2013.

Other Matters

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

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

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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

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policies and estimates related to Revenue Recognition, Impairment of Long Lived Assets and Intangibles, Acquisition Accounting, Depreciation, and ITCs.

Recently Issued Accounting Standards

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

FINANCIAL CONDITION AND LIQUIDITY

Overview

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

Net cash provided from operating activities totaled $371.0 million for the first nine months of 2014, an increase of $82.3 million as compared to the first nine months of 2013. The increase in cash provided from operating activities was primarily due to cash received for ITCs related to new plants placed in service in 2013 and 2014. Net cash used for investing activities totaled $287.6 million for the first nine months of 2014 primarily due to expenditures related to the acquisitions of Adobe and Macho Springs and payments pursuant to long-term service agreements. Net cash used for financing activities totaled $65.4 million for the first nine 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 nine months of 2014 include a $136.0 million increase in plant in service, net of depreciation primarily due to the acquisitions of Adobe and Macho Springs. Other significant changes, which were primarily the result of the timing and amount of ITCs recognized in 2014 as compared to 2013, include a $55.8 million increase in accumulated deferred investment tax credits, and a $25.1 million increase in accumulated deferred income taxes. Additionally, there was a $20.0 million increase in notes payable for commercial paper and a $33.2 million increase in affiliated accounts payable.

Capital Requirements and Contractual Obligations

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Southern Power in Item 7 of the Form 10-K for a description of Southern Power's capital requirements for its construction program, scheduled maturities of long-term debt, as well as the related interest, leases, derivative obligations, purchase commitments, and unrecognized tax benefits. Approximately $525 million will be required through September 30, 2015 to fund maturities of long-term debt.

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. Capital expenditures of Southern Power are currently estimated to be approximately $800 million for 2014, which includes expenditures related to the acquisition of SG2 of approximately $508 million. See Note (I) to the Condensed Financial Statements herein for additional information. 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.

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Sources of Capital

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

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

To meet liquidity and capital resource requirements, Southern Power had at September 30, 2014 cash and cash equivalents of approximately $86.8 million and Southern Power Company had a committed credit facility of $500 million (Facility) expiring in 2018, of which $499 million is unused.

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

Proceeds from this Facility may be used for working capital and general corporate purposes as well as liquidity support for Southern Power Company's commercial paper program. See Note 6 to the financial statements of Southern Power under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (E) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.

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

Details of short-term borrowings were as follows:

	Commercial Paper at the End of the Period				Commercial Paper During the Period(a)
	Amount Outstanding		Weighted Average Interest Rate		Average Outstanding		Weighted Average Interest Rate		Maximum Amount Outstanding
	(in millions)				(in millions)				(in millions)
September 30, 2014:	$	20	0.3	%	$	44	0.3	%	$	83

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

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

Credit Rating Risk

Southern Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB and Baa2, or BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, and energy price risk management.

142

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB and Baa2	$	9
At BBB- and/or Baa3	318
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

During the nine months ended September 30, 2014, Southern Power prepaid $0.8 million of long-term debt payable to TRE and issued $3.9 million due April 30, 2034, $5.3 million due May 31, 2034, $0.8 million due April 30, 2033, and an additional $0.1 million due June 15, 2032 under promissory notes payable to TRE related to the financing of Adobe, Macho Springs, Campo Verde Solar, LLC, and Apex Nevada Solar, LLC, respectively.

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

143

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	145
B	Contingencies and Regulatory Matters	146
C	Fair Value Measurements	164
D	Stockholders' Equity	169
E	Financing	171
F	Retirement Benefits	174
G	Effective Tax Rate and Unrecognized Tax Benefits	177
H	Derivatives	178
I	Acquisitions	185
J	Segment and Related Information	187

INDEX TO APPLICABLE NOTES TO FINANCIAL STATEMENTS BY REGISTRANT

The following unaudited notes to the condensed financial statements are a combined presentation. The list below indicates the registrants to which each footnote applies.

Registrant	Applicable Notes
Southern Company	A, B, C, D, E, F, G, H, I, J
Alabama Power	A, B, C, E, F, G, H
Georgia Power	A, B, C, E, F, G, H
Gulf Power	A, B, C, E, F, G, H
Mississippi Power	A, B, C, E, F, G, H
Southern Power	A, B, C, E, G, H, I

144

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

ALABAMA POWER COMPANY

GEORGIA POWER COMPANY

GULF POWER COMPANY

MISSISSIPPI POWER COMPANY

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

NOTES TO THE CONDENSED FINANCIAL STATEMENTS:

(UNAUDITED)

(A) INTRODUCTION

The condensed quarterly financial statements of each registrant included herein have been prepared by such registrant, without audit, pursuant to the rules and regulations of the SEC. The Condensed Balance Sheets as of December 31, 2013 have been derived from the audited financial statements of each registrant. In the opinion of each registrant's management, the information regarding such registrant furnished herein reflects all adjustments, which, except as otherwise disclosed, are of a normal recurring nature, necessary to present fairly the results of operations for the periods ended September 30, 2014 and 2013. Certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations, although each registrant believes that the disclosures regarding such registrant are adequate to make the information presented not misleading. Disclosures which would substantially duplicate the disclosures in the Form 10-K and details which have not changed significantly in amount or composition since the filing of the Form 10-K are generally omitted from this Quarterly Report on Form 10-Q unless specifically required by GAAP. Therefore, these Condensed Financial Statements should be read in conjunction with the financial statements and the notes thereto included in the Form 10-K. Due to the seasonal variations in the demand for energy, operating results for the periods presented are not necessarily indicative of the operating results to be expected for the full year.

Certain prior year data presented in the financial statements have been reclassified to conform to the current year presentation. These reclassifications had no impact on the results of operations, financial position, or cash flows of any registrant.

Asset Retirement Obligations

See Note 1 to the financial statements of Southern Company and Alabama Power under "Asset Retirement Obligations and Other Costs of Removal" in Item 8 of the Form 10-K for additional information.

Asset retirement obligations (ARO) are computed as the present value of the ultimate costs for an asset's future retirement and are recorded in the period in which the liability is incurred. In September 2014, Alabama Power performed a new ARO liability cost study related to Alabama Power's assets, which increased the estimated ARO liability by approximately $52 million.

As of September 30, 2014 and 2013, details of the ARO related to Alabama Power's assets included in Southern Company's and Alabama Power's Condensed Balance Sheets herein are as follows:

	2014			2013
	(in millions)
Balance at beginning of year	$	730		$	589
Liabilities incurred	—			—
Liabilities settled	(2		)	—
Accretion	33			29
Cash flow revisions	52			102
Balance at end of period	$	813		$	720

The increase in cash flow revisions as of September 30, 2014 primarily relates to an increase in Alabama Power's AROs associated with asbestos at its steam generation facilities.

145

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

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 expense will fluctuate quarterly based on unit run time, but this change in methodology is not expected to have a material impact on an annual basis on the financial statements of Southern Company or Southern Power. The book value of plant-in-service as of September 30, 2014 that is depreciated on a units of production basis was approximately $470 million.

Recently Issued Accounting Standards

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

(B) CONTINGENCIES AND REGULATORY MATTERS

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

General Litigation Matters

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

The ultimate outcome of such pending or potential litigation against each registrant and any subsidiaries cannot be predicted at this time; however, for current proceedings not specifically reported herein or in Note 3 to the financial statements of each registrant in Item 8 of the Form 10-K, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on such registrant's financial statements.

Environmental Matters

New Source Review Actions

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

146

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

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 September 30, 2014 was $19 million. Georgia Power has been designated or identified as a potentially responsible party (PRP) at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), including a site in Brunswick, Georgia on the CERCLA National Priorities List. The parties have completed the removal of wastes from the Brunswick site as ordered by the EPA. Additional cleanup and claims for recovery of natural resource damages at this site or for the assessment and potential cleanup of other sites are anticipated.

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

In addition to the EPA's action at this site, Georgia Power, along with many other parties, was sued in a private action by several existing PRPs for cost recovery related to the removal action. In February 2013, the U.S. District Court for the Eastern District of North Carolina Western Division granted Georgia Power's summary judgment motion ruling that Georgia Power has no liability in the private action. In May 2013, the plaintiffs appealed the U.S. District Court for the Eastern District of North Carolina Western Division's order to the U.S. Court of Appeals for the Fourth Circuit.

The ultimate outcome of these matters will depend upon the success of defenses asserted, the ultimate number of PRPs participating in the cleanup, and numerous other factors and cannot be determined at this time; however, as a result of Georgia Power's regulatory treatment for environmental remediation expenses, these matters are not expected to have a material impact on Southern Company's or Georgia Power's financial statements. See Note 1 to the financial statements of Georgia Power under "Environmental Remediation Recovery" in Item 8 of the Form 10-K for additional information regarding the regulatory treatment.

Gulf Power's environmental remediation liability includes estimated costs of environmental remediation projects of approximately $49.5 million as of September 30, 2014. These estimated costs primarily relate to site closure criteria by the Florida Department of Environmental Protection (FDEP) for potential impacts to soil and groundwater from herbicide applications at Gulf Power substations. The schedule for completion of the remediation projects is subject

147

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

to FDEP approval. The projects have been approved by the Florida PSC for recovery through Gulf Power's environmental cost recovery clause; therefore, there was no impact on net income as a result of these liabilities.

In 2003, Mississippi Power and numerous other entities were designated by the Texas Commission on Environmental Quality (TCEQ) as PRPs at a site that was owned by an electric transformer company that handled Mississippi Power's transformers. The TCEQ approved the final site remediation plan in December 2013 and, on March 28, 2014, the impacted utilities, including Mississippi Power, agreed to commence remediation actions on the site. Mississippi Power's environmental remediation liability is $0.6 million as of September 30, 2014 and is expected to be recovered through the ECO Plan.

The final outcome of these matters cannot be determined at this time. However, based on the currently known conditions at these sites and the nature and extent of activities relating to these sites, management of Southern Company, Georgia Power, Gulf Power, and Mississippi Power does not believe that additional liabilities, if any, at these sites would be material to their respective financial statements.

Nuclear Fuel Disposal Cost Litigation

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

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

In 2008 and again on March 4, 2014, Alabama Power and Georgia Power filed additional lawsuits against the U.S. government for the costs of continuing to store spent nuclear fuel at Plants Farley and Hatch and Plant Vogtle Units 1 and 2 for the period from January 1, 2005 through December 31, 2010 and from January 1, 2011 through December 31, 2013, respectively. Damages will continue to accumulate until the issue is resolved or storage is provided. The final outcome of these matters cannot be determined at this time; however, no material impact on Southern Company's, Alabama Power's, or Georgia Power's net income is expected.

On-site dry spent fuel storage facilities are operational at all three plants and can be expanded to accommodate spent fuel through the expected life of each plant.

FERC Matters

See Note 3 to the financial statements of Mississippi Power under "FERC Matters" in Item 8 of the Form 10-K for additional information regarding the authority to defer in a regulatory asset costs related to the retirement or partial retirement of generating units as a result of environmental compliance rules. See Note 3 to the financial statements of Southern Company under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K, Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K, and "Integrated Coal Gasification Combined Cycle" herein for information regarding Mississippi Power's construction of the Kemper IGCC.

On March 31, 2014, Mississippi Power reached a settlement agreement with its wholesale customers and filed a request with the FERC for an increase in the Municipal and Rural Associations (MRA) cost-based electric tariff. The settlement agreement, approved by the FERC on May 20, 2014, provides that base rates under the MRA cost-based electric tariff will increase approximately $10.1 million annually, with revised rates effective for services rendered beginning May 1, 2014.

148

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Retail Regulatory Matters

Alabama Power

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

Regulatory Clause	Balance Sheet Line Item	September 30, 2014		December 31, 2013
		(in millions)
Rate CNP Environmental – Under	Deferred under recovered regulatory clause revenues	$	—	$	7
	Under recovered regulatory clause revenues, current	25		—
Rate CNP PPA – Under	Deferred under recovered regulatory clause revenues	46		18
	Under recovered regulatory clause revenues, current	9		—
Retail Energy Cost Recovery – Over	Other regulatory liabilities, current	44		27
	Deferred over recovered regulatory clause revenues	—		15
Natural Disaster Reserve	Other regulatory liabilities, deferred	87		96

Georgia Power

Rate Plans

See Note 3 to the financial statements of Southern Company and Georgia Power under "Retail Regulatory Matters – Georgia Power – Rate Plans" and "Retail Regulatory Matters – Rate Plans," respectively, in Item 8 of the Form 10-K for additional information on Georgia Power's 2013 ARP.

In accordance with the terms of the 2013 ARP, on October 3, 2014, Georgia Power filed the following tariff adjustments with the Georgia PSC to become effective January 1, 2015 pending its approval:

• Increase the traditional base tariffs by approximately $107 million to cover additional capacity costs;

• Increase the environmental compliance cost recovery tariff by approximately $32 million;

• Increase the demand-side management tariffs by approximately $3 million; and

• Increase the municipal franchise fee tariff by approximately $3 million, consistent with the adjustments above.

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

Renewables Development

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

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

As a result of amendments executed during 2014, the biomass PPAs classified as non-affiliate capital leases with related long-term obligations totaling $641 million as of December 31, 2013 no longer meet the definition of a lease or will be accounted for as operating leases. Due to these amendments, as well as others executed during 2014, total non-affiliate operating lease long-term obligations increased by $103 million. As such, estimated long-term obligations for non-affiliate operating leases have been updated to $113 million for 2015, $117 million for 2016, $145 million for 2017, $150 million for 2018, and $1.7 billion for 2019 and thereafter. Estimated long-term

149

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

obligations did not change for 2014. The counterparties of the aforementioned PPAs have posted collateral as required. See Note 7 to the financial statements of Georgia Power under "Commitments – Fuel and Purchased Power Agreements" in Item 8 of the Form 10-K for additional information.

Integrated Resource Plan

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

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

Fuel Cost Recovery

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

As of September 30, 2014, Georgia Power's under recovered fuel balance totaled $175 million and is included in deferred charges and other 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. Georgia Power's next fuel case is expected to be filed with the Georgia PSC by February 27, 2015.

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

Storm Damage Recovery

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

Georgia Power defers and recovers certain costs related to damages from major storms as mandated by the Georgia PSC. As of September 30, 2014 and December 31, 2013, the balance in the regulatory asset related to storm damage was $105 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, Vogtle Construction Monitoring (VCM) reports, and pending litigation.

In 2008, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into an agreement (Vogtle 3 and 4 Agreement) with the Contractor, pursuant to which the Contractor agreed to design, engineer, procure, construct, and test Plant Vogtle Units 3 and 4. Under the terms of the Vogtle 3 and 4 Agreement, the Vogtle Owners agreed to pay a purchase price that is subject to certain price escalations and adjustments, including fixed escalation amounts and index-based adjustments, as well as adjustments for change orders, and performance bonuses for early

150

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

completion and unit performance. Each Vogtle Owner is severally (and not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to the Contractor under the Vogtle 3 and 4 Agreement. Georgia Power's proportionate share is 45.7%. 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 Vogtle 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 Vogtle Owner, such Vogtle Owner will be required to provide a letter of credit or other credit enhancement. The Vogtle Owners may terminate the Vogtle 3 and 4 Agreement at any time for their convenience, provided that the Vogtle Owners will be required to pay certain termination costs. The Contractor may terminate the Vogtle 3 and 4 Agreement under certain circumstances, including certain Vogtle Owner suspension or delays of work, action by a governmental authority to permanently stop work, certain breaches of the Vogtle 3 and 4 Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events.

In 2009, the NRC issued an Early Site Permit and Limited Work Authorization which allowed limited work to begin on Plant Vogtle Units 3 and 4. The NRC certified the Westinghouse Design Control Document, as amended (DCD), for the AP1000 nuclear reactor design, in late 2011, and issued combined construction and operating licenses (COLs) in early 2012. Receipt of the COLs allowed full construction to begin. There have been technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4, at the federal and state level, and additional challenges are expected as construction proceeds.

In 2009, the Georgia PSC approved inclusion of the Plant Vogtle Units 3 and 4 related CWIP accounts in rate base, and the State of Georgia enacted the Georgia Nuclear Energy Financing Act, which allows Georgia Power to recover financing costs for nuclear construction projects certified by the Georgia PSC. Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff by including the related CWIP accounts in rate base during the construction period. The Georgia PSC approved increases to the NCCR tariff of approximately $223 million, $35 million, $50 million, and $60 million, effective January 1, 2011, 2012, 2013, and 2014, respectively. On October 31, 2014, Georgia Power filed to increase the NCCR tariff by approximately $27 million effective January 1, 2015 pending Georgia PSC approval. 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 September 30, 2014, approximately $23 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. Associated financing costs during the construction period are estimated to total approximately $2.0 billion.

In September 2013, the Georgia PSC approved a stipulation entered into by Georgia Power and the Georgia PSC staff to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate, until the completion of Plant Vogtle Unit 3, or earlier if deemed appropriate by the Georgia PSC and Georgia Power. In accordance with the Georgia Integrated Resource Planning Act, any costs incurred by Georgia Power in excess of the certified amount will not be included in rate base, unless shown to be reasonable and prudent. In addition, financing costs on any excess construction-related costs potentially would be subject to recovery through AFUDC instead of the NCCR tariff. On August 19, 2014, the Georgia PSC approved a combined ninth and tenth VCM report covering the period from January 1 through December 31, 2013 (Ninth/Tenth VCM report), including construction capital costs incurred, which through December 31, 2013 totaled $2.6 billion. Georgia Power resumed filing semi-annual reports

151

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

with the eleventh VCM report filed on August 28, 2014, which requests approval of an additional $0.2 billion in costs incurred from January 1, 2014 through June 30, 2014.

In 2012, the Vogtle Owners and the Contractor began negotiations regarding the costs associated with design changes to the DCD and the delays in the timing of approval of the DCD and issuance of the COLs, including the assertion by the Contractor that the Vogtle Owners are responsible for these costs under the terms of the Vogtle 3 and 4 Agreement. Also in 2012, Georgia Power and the other Vogtle Owners filed suit against the Contractor in the U.S. District Court for the Southern District of Georgia seeking a declaratory judgment that the Vogtle Owners are not responsible for these costs. In 2012, the Contractor also filed suit against Georgia Power and the other Vogtle Owners in the U.S. District Court for the District of Columbia alleging the Vogtle Owners are responsible for these costs. In August 2013, the U.S. District Court for the District of Columbia dismissed the Contractor's suit, ruling that the proper venue is the U.S. District Court for the Southern District of Georgia. The Contractor appealed the decision to the U.S. Court of Appeals for the District of Columbia Circuit in September 2013. The portion of additional costs claimed by the Contractor in its initial complaint that would be attributable to Georgia Power (based on Georgia Power's ownership interest) is approximately $425 million (in 2008 dollars). The Contractor also asserted it is entitled to further schedule extensions. On May 22, 2014, the Contractor filed an amended counterclaim to the suit pending in the U.S. District Court for the Southern District of Georgia alleging that (i) the design changes to the DCD imposed by the NRC delayed module production and the impacts to the Contractor are recoverable by the Contractor under the Vogtle 3 and 4 Agreement and (ii) the changes to the basemat rebar design required by the NRC caused additional costs and delays recoverable by the Contractor under the Vogtle 3 and 4 Agreement. The Contractor did not specify in its amended counterclaim the amounts relating to these new allegations, but the Contractor subsequently asserted, and may from time to time continue to assert, that it is entitled to additional payments with respect to these new allegations, any of which could be substantial. Georgia Power does not agree with either the proposed cost or schedule adjustments or that the Vogtle Owners have any responsibility for costs related to these issues. Litigation is ongoing and Georgia Power intends to vigorously defend the positions of the Vogtle Owners. Georgia Power also expects negotiations with the Contractor to continue with respect to cost and schedule during which negotiations the parties may reach a mutually acceptable compromise of their positions.

Processes are in place that are designed to assure compliance with the requirements specified in the DCD and the COLs, including inspections by Southern Nuclear and the NRC that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the NRC. Various design and other licensing-based compliance issues are expected to arise as construction proceeds, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs either to the Vogtle Owners or the Contractor or to both.

As construction continues, the risk remains that ongoing challenges with Contractor performance including additional challenges in the fabrication, assembly, delivery, and installation of the shield building and structural modules, delays in the receipt of the remaining permits necessary for the operation of Plant Vogtle Units 3 and 4, or other issues could arise and may further impact project schedule and cost. While Georgia Power expects the Contractor to employ mitigation efforts to maintain the current project schedule and believes the Contractor is responsible for any related costs, Contractor performance and progress in recent months on the assembly and installation of the shield building and structural modules have resulted in additional schedule pressure.

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

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

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Gulf Power

Retail Base Rate Case

See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Retail Base Rate Case" in Item 8 of the Form 10-K for additional information.

In December 2013, the Florida PSC approved a settlement agreement that provides Gulf Power may reduce depreciation expense and record a regulatory asset up to $62.5 million between January 2014 and June 2017. In any given month, such depreciation expense reduction may not exceed the amount necessary for the ROE, as reported to the Florida PSC monthly, to reach the midpoint of the authorized retail ROE range then in effect. Gulf Power recognized a $5.4 million reduction in depreciation expense in the first nine months of 2014.

Cost Recovery Clauses

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

Recovery Clause	Balance Sheet Location	September 30, 2014		December 31, 2013
		(in millions)
Fuel Cost Recovery – Under	Under recovered regulatory clause revenues	$	41.3	$	21.0
Purchased Power Capacity Recovery – Over	Other regulatory liabilities, current	6.8		—
Purchased Power Capacity Recovery – Under	Under recovered regulatory clause revenues	—		2.8
Environmental Cost Recovery – Under	Under recovered regulatory clause revenues	6.3		14.4
Energy Conservation Cost Recovery – Under	Under recovered regulatory clause revenues	2.6		7.0

On October 22, 2014, the Florida PSC approved Gulf Power's annual rate clause request for its fuel, purchased power capacity, environmental, and energy conservation cost recovery factors for 2015. The net effect of the approved changes is a $41.2 million increase in annual revenue for 2015. The increased revenues will not have a significant impact on net income since most of the revenues will be offset by expenses.

Retail Fuel Cost Recovery

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

Gulf Power has established fuel cost recovery rates as approved annually by the Florida PSC. In late 2013 and the first half of 2014, Gulf Power experienced higher than expected costs for natural gas and purchased power. If the projected year-end fuel cost over or under recovery balance exceeds 10% of the projected fuel revenues for the period, Gulf Power is required to notify the Florida PSC and indicate if an adjustment to the fuel recovery factor is being requested. Gulf Power filed such notice with the Florida PSC on July 18, 2014, but no adjustment to the factor was requested for 2014. Under recovered fuel costs at September 30, 2014 totaled $41.3 million and are included in under recovered regulatory clause revenues on Gulf Power's Condensed Balance Sheet herein. Fuel cost recovery revenues, as recorded on the financial statements, are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, any changes in the billing factor would have no significant effect on Gulf Power's revenues or net income, but will affect cash flow.

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Mississippi Power

Energy Efficiency

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

On June 3, 2014, the Mississippi PSC approved Mississippi Power's 2014 Energy Efficiency Quick Start Plan filing, which includes a portfolio of energy efficiency programs. On October 17, 2014, Mississippi Power filed a revised compliance filing, which proposed an increase of $6.7 million in retail revenues for the period December 2014 through December 2015. The Mississippi PSC approved the revised filing on November 4, 2014.

Performance Evaluation Plan

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

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

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

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

System Restoration Rider

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

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

Environmental Compliance Overview Plan

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

In 2012, the Mississippi PSC approved Mississippi Power's request for a CPCN to construct a scrubber on Plant Daniel Units 1 and 2. These units are jointly owned by Mississippi Power and Gulf Power, with 50% ownership each. The estimated total cost of the project is approximately $660 million, with Mississippi Power's portion being $330 million, excluding AFUDC. The project is scheduled for completion in December 2015. Mississippi Power's portion of the cost is expected to be recovered through the ECO Plan following the scheduled completion of the project in December 2015. As of September 30, 2014, total project expenditures were $464.1 million, of which Mississippi Power's portion was $236.3 million, plus AFUDC of $16.1 million.

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

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CPCN to construct a scrubber on Plant Daniel Units 1 and 2. On August 28, 2014, the Chancery Court dismissed the appeal.

In accordance with a 2011 accounting order from the Mississippi PSC, Mississippi Power has the authority to defer in a regulatory asset for future recovery all plant retirement- or partial retirement-related costs resulting from environmental regulations. As of September 30, 2014, $5.5 million of Plant Greene County CWIP had been reclassified as a regulatory asset. Additional costs associated with the remaining net book value of coal-related equipment will be reclassified to a regulatory asset at the time of retirement for Plants Greene County and Watson. Approved regulatory asset costs will be amortized over a period to be determined by the Mississippi PSC. As a result, these decisions are not expected to have a material impact on Southern Company's and Mississippi Power's financial statements. See "Other Matters – Sierra Club Settlement Agreement" herein for additional information.

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

Fuel Cost Recovery

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

At September 30, 2014, the amount of under recovered retail fuel costs included on Mississippi Power's Condensed Balance Sheet herein was $13.1 million compared to over recovered retail fuel costs of $14.5 million at December 31, 2013.

Ad Valorem Tax Adjustment

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

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

Integrated Coal Gasification Combined Cycle

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

Kemper IGCC Project Approval

In 2012, the Mississippi PSC issued the 2012 MPSC CPCN Order, a detailed order confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing the acquisition, construction, and operation of the Kemper IGCC, which the Sierra Club appealed to the Chancery Court. Later in 2012, the Chancery Court affirmed the 2012 MPSC CPCN Order. In January 2013, the Sierra Club filed an appeal of the Chancery Court's ruling with the Mississippi Supreme Court.

On August 1, 2014, Mississippi Power entered into the Sierra Club Settlement Agreement that, among other things, requires the Sierra Club to dismiss or withdraw all pending legal and regulatory challenges against the Kemper IGCC, including the appeal to the Mississippi Supreme Court related to the 2012 MPSC CPCN. On August 4, 2014, Mississippi Power and the Sierra Club filed a joint motion to dismiss the appeal related to the 2012 MPSC CPCN, which the Mississippi Supreme Court granted on September 11, 2014. See "Other Matters – Sierra Club Settlement Agreement" herein for additional information.

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

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facilities, and AFUDC related to the Kemper IGCC. The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, with recovery of prudently-incurred costs subject to approval by the Mississippi PSC. Exceptions to the $2.88 billion cost cap include the cost of the lignite mine and equipment, the cost of the CO₂ pipeline facilities, AFUDC, and certain general exceptions, including change of law, force majeure, and beneficial capital (which exists when Mississippi Power demonstrates that the purpose and effect of the construction cost increase is to produce efficiencies that will result in a neutral or favorable effect on customers relative to the original proposal for the CPCN) (Cost Cap Exceptions), as contemplated in the 2013 Settlement Agreement (defined below) and the 2012 MPSC CPCN Order. Recovery of the Cost Cap Exception amounts remains subject to review and approval by the Mississippi PSC.

The Kemper IGCC was originally projected to be placed in service in May 2014. Mississippi Power placed the combined cycle and the associated common facilities portion of the Kemper IGCC in service on natural gas on August 9, 2014, and continues to focus on completing the remainder of the Kemper IGCC, including the gasifier and the gas clean-up facilities, for which the in-service date is currently expected to occur in the first half of 2016. In accordance with a Mississippi PSC order, on August 18, 2014, Mississippi Power provided an analysis of the costs and benefits of placing the combined cycle and the associated common facilities portion of the Kemper IGCC in service, including the expected accounting treatment. Mississippi Power's analysis requested, among other things, confirmation of Mississippi Power's accounting treatment by the Mississippi PSC of (1) the continued collection of rates as prescribed by the 2013 MPSC Rate Order (defined below), with the current recognition as revenue of the related equity return on all assets placed in service, and the deferral of all remaining rate collections under the 2013 MPSC Rate Order to a regulatory liability account, (2) the continued accrual of AFUDC through the in-service date of the remainder of the Kemper IGCC, and (3) the deferral of operating costs for the combined cycle as regulatory assets. Under Mississippi Power's proposal, non-incremental costs that would have been incurred whether or not the combined cycle was placed in service would be included in a regulatory asset and would continue to be subject to the $2.88 billion cost cap. Additionally, incremental costs that would not have been incurred if the combined cycle had not gone into service would be included in a regulatory asset and would not be subject to the cost cap because these costs are incurred to support operation of the combined cycle. All energy revenues associated with the combined cycle variable operating and maintenance expenses would be credited to this regulatory asset. See "Regulatory Assets and Liabilities" herein for additional information.

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

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

Cost Category	2010 Project Estimate(f)		Current Estimate		Actual Costs at September 30, 2014
	(in billions)
Plant Subject to Cost Cap(a)	$	2.40	$	4.86	$	4.06
Lignite Mine and Equipment	0.21		0.23		0.23
CO2 Pipeline Facilities	0.14		0.11		0.10
AFUDC(b)(c)	0.17		0.62		0.41
Combined Cycle and Related Assets Placed in Service – Incremental(d)	—		—		—
General Exceptions	0.05		0.10		0.07
Regulatory Asset(c)(e)	—		0.18		0.10
Total Kemper IGCC(a)(c)	$	2.97	$	6.10	$	4.97

(a) The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, net of the DOE Grants and excluding the Cost Cap Exceptions. The Current Estimate and Actual Costs include non-incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service in August 2014 that are subject to the $2.88 billion cost cap.

(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 March 31, 2016.

(d) Incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service on August 9, 2014, net of costs related to energy sales.

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

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

Of the total costs incurred as of September 30, 2014, $2.88 billion was included in property, plant, and equipment (which is net of the DOE Grants and estimated probable losses of $1.98 billion), $104.3 million in other regulatory assets, and $3.9 million in other deferred charges and assets in Southern Company's and Mississippi Power's Condensed Balance Sheets herein, and $1.1 million was previously expensed.

Mississippi Power does not intend to seek any rate recovery or joint owner contributions for any related costs that exceed the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions. Southern Company and Mississippi Power recorded pre-tax charges to income for revisions to the cost estimate of $418.0 million ($258.1 million after tax) in the third quarter 2014 and $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 reflected 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. The third quarter 2014 revised cost estimate primarily reflects costs related to the extension of the project schedule for the remainder of the Kemper IGCC (including the gasifier and the gas clean-up facilities) as a result of matters related to the time expected to be required for start-up activities and operational readiness, including enhancing the scope of specialized operator training. The current estimate includes costs through March 31, 2016. Any further extension of the in-service date is currently estimated to result in additional base costs of approximately $20 million to $30 million per month, which includes maintaining necessary levels of start-up labor, materials, and fuel, as well as operational resources required to execute start-up and commissioning activities.

Any further 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

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inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under construction or other agreements, operational performance, operational readiness, including specialized operator training, unforeseen engineering or design problems, start-up activities for this first-of-a-kind technology (including major equipment failure and system integration), and/or operations. In subsequent periods, any further changes in the estimated costs to complete construction and start-up of the Kemper IGCC subject to the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions, will be reflected in Southern Company's statements of income and Mississippi Power's statements of operations and these changes could be material.

Rate Recovery of Kemper IGCC Costs

The ultimate outcome of the rate recovery matters discussed herein, including the resolution of legal challenges, determinations of prudency, and the specific manner of recovery of prudently-incurred costs, cannot be determined at this time, but could have a material impact on Southern Company's and Mississippi Power's results of operations, financial condition, and liquidity.

2012 MPSC CPCN Order

The 2012 MPSC CPCN Order included provisions relating to both Mississippi Power's recovery of financing costs during the course of construction of the Kemper IGCC and Mississippi Power's recovery of costs following the date the Kemper IGCC is placed in service. With respect to recovery of costs following the in-service date of the Kemper IGCC, the 2012 MPSC CPCN Order provided for the establishment of operational cost and revenue parameters based upon assumptions in Mississippi Power's petition for the CPCN. Mississippi Power expects the Mississippi PSC to apply operational parameters in connection with the evaluation of the 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.

2013 Settlement Agreement

In January 2013, Mississippi Power entered into a settlement agreement with the Mississippi PSC that, among other things, establishes the process for resolving matters regarding cost recovery related to the Kemper IGCC and dismissed Mississippi Power's appeal of the 2012 MPSC CWIP Order (2013 Settlement Agreement). Under the 2013 Settlement Agreement, Mississippi Power agreed to limit the portion of prudently-incurred Kemper IGCC costs to be included in retail rate base to the $2.4 billion certificated cost estimate, plus the Cost Cap Exceptions, but excluding AFUDC, and any other costs permitted or determined to be excluded from the $2.88 billion cost cap by the Mississippi PSC. The 2013 Settlement Agreement also allows Mississippi Power to secure alternate financing for costs that are not otherwise recovered in any Mississippi PSC rate proceedings contemplated by the 2013 Settlement Agreement. Legislation to authorize a multi-year rate plan and legislation to provide for alternate financing through securitization of up to $1.0 billion of prudently-incurred costs was enacted into law in February 2013. Mississippi Power intends to securitize (1) prudently-incurred costs in excess of the certificated cost estimate and up to the $2.88 billion cost cap, net of the DOE Grants and excluding the Cost Cap Exceptions, (2) accrued AFUDC, and (3) other prudently-incurred costs, which include carrying costs from the estimated in-service date until securitization is finalized and other costs not included in the Seven-Year Rate Plan (described below) 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. With the extension of the Kemper IGCC in-service date, under certain potential scenarios, the amount eligible to be securitized may exceed $1.0 billion. In that event, Mississippi Power would expect to pursue rate recovery of any additional eligible costs.

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

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Agreement. Mississippi Power continues to work with the Mississippi PSC and the Mississippi Public Utilities Staff (MPUS) to implement the requirements of the 2013 Settlement Agreement.

2013 MPSC Rate Order

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

In March 2013, the Mississippi PSC issued a 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 (2013 MPSC Rate Order). For the first nine months of 2014, $121.9 million has been collected, with $16.8 million recognized in retail revenues in Southern Company's Statements of Income and Mississippi Power's Condensed Statements of Operations herein and the remainder deferred in other regulatory liabilities to be used to mitigate customer rate impacts after the Kemper IGCC is placed in service and included in Southern Company's and Mississippi Power's Condensed Balance Sheets herein. Since March 2013, $220.0 million has been collected, with $27.1 million recognized in retail revenues in Southern Company's Statements of Income and Mississippi Power's Condensed Statements of Operations herein, and the remainder deferred in other regulatory liabilities to be used to mitigate customer rate impacts after the Kemper IGCC is placed in service and included in Southern Company's and Mississippi Power's Condensed Balance Sheets herein.

Because the 2013 MPSC Rate Order did not provide for the inclusion of CWIP in rate base as permitted by the Baseload Act, Mississippi Power continues to record AFUDC on the Kemper IGCC through the in-service date. Mississippi Power will not record AFUDC on any additional costs of the Kemper IGCC that exceed the $2.88 billion cost cap, except for Cost Cap Exception amounts. Mississippi Power will continue to record AFUDC and to comply with the 2013 MPSC Rate Order by collecting and deferring the approved rates through the in-service date 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. An adverse outcome could affect the rates that went into effect on March 19, 2013 and January 1, 2014 and the related amounts deferred as a regulatory liability.

See "Regulatory Assets and Liabilities" herein for additional information.

Seven-Year Rate Plan

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

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

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2012 (ATRA), which currently requires that assets be placed in service in 2014. While Mississippi Power placed the combined cycle and the associated common facilities portion of the Kemper IGCC in service on August 9, 2014, extension of the in-service date for the remainder of the Kemper IGCC beyond 2014 results in the loss of tax benefits related to bonus depreciation under current law. The estimated value to retail customers of the bonus depreciation tax benefits not associated with the combined cycle and the associated common facilities portion of the Kemper IGCC is approximately $130 million to $160 million.

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 investment tax credits, various other revenue requirement items, and other tax matters, including bonus depreciation, which include ensuring compliance with the normalization requirements of the Internal Revenue Code. The impact of these revisions for the average annual retail revenue requirement is estimated to be an increase of approximately $60 million to $70 million through 2020. The revision of the Seven-Year Rate Plan is also expected to reflect rate mitigation options identified by Mississippi Power, including Section 174 Research and Experimental (R&E) tax deductions, 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. See "Income Tax Matters" herein for additional information.

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 alternate means, which could include a traditional rate case.

In addition to current estimated costs at September 30, 2014 of $6.10 billion, Mississippi Power anticipates that it will incur additional costs after the Kemper IGCC in-service date until the Seven-Year Rate Plan, as ultimately amended or revised, and securitization are finalized. These costs include, but are not limited to, regulatory costs and additional carrying costs which could be material. Recovery of these costs would be subject to approval by the Mississippi PSC.

Prudence Reviews

The Mississippi PSC's review of Kemper IGCC costs is ongoing. On August 5, 2014, the Mississippi PSC ordered that a consolidated prudence determination of all Kemper IGCC costs be completed after the entire project has been placed in service and has demonstrated availability for a reasonable period of time as determined by the Mississippi PSC and the MPUS. The Mississippi PSC has encouraged the parties to work in good faith to settle contested issues and Mississippi Power is working to reach a mutually acceptable resolution.

Regulatory Assets and Liabilities

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 through the in-service date, subject to review of such costs by the Mississippi PSC. Such costs include, but are not limited to, interest costs on Kemper assets currently placed in service, costs associated with Mississippi PSC and MPUS consultants, prudence costs, legal fees, and operating expenses associated with assets placed in service.

On August 18, 2014, Mississippi Power requested confirmation by the Mississippi PSC of Mississippi Power's authority to defer all operating expenses associated with the operation of the combined cycle subject to review of such costs by the Mississippi PSC. In addition, Mississippi Power is authorized to accrue carrying costs on the unamortized balance of such regulatory assets at a rate and in a manner to be determined by the Mississippi PSC in future cost recovery mechanism proceedings. As of September 30, 2014, the regulatory asset balance associated with the Kemper IGCC was $104.3 million. The projected balance at March 31, 2016 is estimated to total approximately $180 million. 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.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

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. Because the 2013 MPSC Rate Order did not provide for the inclusion of CWIP in rate base as permitted by the Baseload Act, Mississippi Power continues to record AFUDC on the Kemper IGCC through the in-service date. To comply with the 2013 MPSC Rate Order, Mississippi Power is deferring the collections under the approved rates through the in-service date in a regulatory liability to be amortized and used to mitigate customer rate impacts after the Kemper IGCC is placed in service. Mississippi Power is accruing interest costs on the unamortized balance of such regulatory liability for the benefit of retail customers. The disposition of the regulatory liability will be determined by the Mississippi PSC in future cost recovery mechanism proceedings.

Lignite Mine and CO₂ Pipeline Facilities

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

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

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

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

Proposed Sale of Undivided Interest to SMEPA

In 2010, Mississippi Power and SMEPA entered into an asset purchase agreement (APA) whereby SMEPA agreed to purchase a 17.5% undivided interest in the Kemper IGCC. In 2012, the Mississippi PSC approved the sale and transfer of the 17.5% undivided interest in the Kemper IGCC to SMEPA. Later in 2012, Mississippi Power and SMEPA signed an amendment to the APA whereby SMEPA reduced its purchase commitment percentage from a 17.5% to a 15% undivided interest in the Kemper IGCC. In March 2013, Mississippi Power and SMEPA signed an amendment to the APA whereby 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.

161

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

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

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

The letter agreement also provides for certain post-closing adjustments to address any differences between the actual and the estimated amounts of post-in-service date costs (both expenses and capital) and revenue credits for those portions of the Kemper IGCC previously placed in service. In addition, if the parties approve an amendment to the APA incorporating the terms of the letter agreement but do not execute the amendment before December 31, 2014, the parties agreed to extend the current APA through December 31, 2015.

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

On October 9, 2014, Mississippi Power received an additional $50 million deposit from SMEPA to be applied to the purchase.

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.

162

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Investment Tax Credits and Bonus Depreciation

The IRS allocated $279 million (Phase II) of Internal Revenue Code Section 48A tax credits to Mississippi Power in connection with the Kemper IGCC. Through September 30, 2014, Mississippi Power had recorded tax benefits totaling $276.4 million for the Phase II credits, of which approximately $140 million have been utilized through that date. These credits will be amortized as a reduction to depreciation and amortization over the life of the Kemper IGCC and are dependent upon meeting the IRS certification requirements, including an in-service date no later than April 19, 2016 and the capture and sequestration (via enhanced oil recovery) of at least 65%of the CO₂ produced by the Kemper IGCC during operations in accordance with the Internal Revenue Code. 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 will apply primarily to the combined cycle and associated common facilities portion of the Kemper IGCC that were placed in service on August 9, 2014. The estimated cash flow benefit is approximately $100 million. See "Rate Recovery of Kemper IGCC Costs – Seven-Year Rate Plan" herein for additional information.

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

Other Matters

Sierra Club Settlement Agreement

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

Under the Sierra Club Settlement Agreement, Mississippi Power agreed to, among other things, fund a $15 million grant payable over a 15-year period for an energy efficiency and renewable program and contribute $2 million to a conservation fund. In accordance with the Sierra Club Settlement Agreement, Mississippi Power paid $7 million in the third quarter 2014, recognized in other income (expense), net in Southern Company's Statements of Income and Mississippi Power's Condensed Statements of Operations herein. In addition, and consistent with Mississippi Power's ongoing evaluation of recent environmental rules and regulations, Mississippi Power agreed to retire, repower with natural gas, or convert to an alternative non-fossil fuel source Plant Sweatt Units 1 and 2 (80 MWs) no later than December 2018. Mississippi Power also agreed that it would cease burning coal and other solid fuel at Plant Watson Units 4 and 5 (750 MWs) and begin operating those units solely on natural gas no later than April 2015, and cease burning coal and other solid fuel at Plant Greene County Units 1 and 2 (200 MWs) and begin operating those units solely on natural gas no later than April 2016. See "Retail Regulatory Matters – Mississippi Power – Environmental Compliance Overview Plan" herein for additional information.

163

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

(C) FAIR VALUE MEASUREMENTS

As of September 30, 2014, assets and liabilities measured at fair value on a recurring basis during the period, together with the level of the fair value hierarchy in which they fall, were as follows:

	Fair Value Measurements Using
As of September 30, 2014:	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
	(in millions)
Southern Company
Assets:
Energy-related derivatives	$	—	$	12	$	—	$	12
Nuclear decommissioning trusts(a)	632		875		2		1,509
Cash equivalents	955		—		—		955
Other investments	9		—		1		10
Total	$	1,596	$	887	$	3	$	2,486
Liabilities:
Energy-related derivatives	$	—	$	53	$	—	$	53
Interest rate derivatives	—		2		—		2
Total	$	—	$	55	$	—	$	55
Alabama Power
Assets:
Energy-related derivatives	$	—	$	5	$	—	$	5
Nuclear decommissioning trusts(b)
Domestic equity	399		78		—		477
Foreign equity	34		65		—		99
U.S. Treasury and government agency securities	—		34		—		34
Corporate bonds	—		98		—		98
Mortgage and asset backed securities	—		19		—		19
Other	—		8		2		10
Cash equivalents	543		—		—		543
Total	$	976	$	307	$	2	$	1,285
Liabilities:
Energy-related derivatives	$	—	$	11	$	—	$	11
Interest rate derivatives	—		1		—		1
Total	$	—	$	12	$	—	$	12

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

	Fair Value Measurements Using
As of September 30, 2014:	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
	(in millions)
Georgia Power
Assets:
Energy-related derivatives	$	—	$	1	$	—	$	1
Nuclear decommissioning trusts(b) (c)
Domestic equity	191		2		—		193
Foreign equity	—		132		—		132
U.S. Treasury and government agency securities	—		126		—		126
Municipal bonds	—		25		—		25
Corporate bonds	—		169		—		169
Mortgage and asset backed securities	—		114		—		114
Other	8		5		—		13
Total	$	199	$	574	$	—	$	773
Liabilities:
Energy-related derivatives	$	—	$	12	$	—	$	12
Gulf Power
Assets:
Energy-related derivatives	$	—	$	3	$	—	$	3
Cash equivalents	18		—		—		18
Total	$	18	$	3	$	—	$	21
Liabilities:
Energy-related derivatives	$	—	$	19	$	—	$	19
Mississippi Power
Assets:
Energy-related derivatives	$	—	$	2	$	—	$	2
Cash equivalents	45		—		—		45
Total	$	45	$	2	$	—	$	47
Liabilities:
Energy-related derivatives	$	—	$	10	$	—	$	10
Southern Power
Assets:
Energy-related derivatives	$	—	$	1	$	—	$	1
Cash equivalents	80		—		—		80
Total	$	80	$	1	$	—	$	81
Liabilities:
Energy-related derivatives	$	—	$	1	$	—	$	1

(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.

165

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

(c) Includes the investment securities pledged to creditors and cash collateral received and excludes payables related to the securities lending program. As of September 30, 2014, approximately $58 million of the fair market value of Georgia Power's nuclear decommissioning trust funds' securities were on loan and pledged to creditors under the funds' managers' securities lending program.

Valuation Methodologies

The energy-related derivatives primarily consist of over-the-counter financial products for natural gas and physical power products including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and overnight index swap interest rates. Interest rate and foreign currency derivatives are also standard over-the-counter financial products valued using the market approach. Inputs for interest rate derivatives include LIBOR interest rates, interest rate futures contracts, and occasionally implied volatility of interest rate options. Inputs for foreign currency derivatives are from observable market sources. See Note (H) herein for additional information on how these derivatives are used.

For fair value measurements of investments within the nuclear decommissioning trusts, specifically the fixed income assets using significant other observable inputs and unobservable inputs, the primary valuation technique used is the market approach. External pricing vendors are designated for each of the asset classes in the nuclear decommissioning trusts with each security discriminately assigned a primary pricing source, based on similar characteristics. A market price secured from the primary source vendor is then evaluated by management in its valuation of the assets within the trusts. As a general approach, market pricing vendors gather market data (including indices and market research reports) and integrate relative credit information, observed market movements, and sector news into proprietary pricing models, pricing systems, and mathematical tools. Dealer quotes and other market information including live trading levels and pricing analysts' judgment are also obtained when available. Investments in private equity and real estate within the nuclear decommissioning trusts are generally classified as Level 3, as the underlying assets typically do not have observable inputs. The fund manager values these assets using various inputs and techniques depending on the nature of the underlying investments. The fair value of partnerships is determined by aggregating the value of the underlying assets.

"Other investments" include investments in funds that are valued using the market approach and income approach. Securities that are traded in the open market are valued at the closing price on their principal exchange as of the measurement date. 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.

166

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

As of September 30, 2014, the fair value measurements of investments calculated at net asset value per share (or its equivalent), as well as the nature and risks of those investments, were as follows:

As of September 30, 2014:	Fair Value		Unfunded Commitments	Redemption Frequency	Redemption Notice Period
	(in millions)
Southern Company
Nuclear decommissioning trusts:
Foreign equity funds	$	132	None	Monthly	5 days
Equity - commingled funds	65		None	Daily/Monthly	Daily/7 days
Other - commingled funds	5		None	Daily	Not applicable
Other - money market funds	8		None	Daily	Not applicable
Trust-owned life insurance	112		None	Daily	15 days
Cash equivalents:
Money market funds	955		None	Daily	Not applicable
Alabama Power
Nuclear decommissioning trusts:
Equity - commingled funds	$	65	None	Daily/Monthly	Daily/7 days
Trust-owned life insurance	112		None	Daily	15 days
Cash equivalents:
Money market funds	543		None	Daily	Not applicable
Georgia Power
Nuclear decommissioning trusts:
Foreign equity funds	$	132	None	Monthly	5 days
Other - commingled funds	5		None	Daily	Not applicable
Other - money market funds	8		None	Daily	Not applicable
Gulf Power
Cash equivalents:
Money market funds	$	18	None	Daily	Not applicable
Mississippi Power
Cash equivalents:
Money market funds	$	45	None	Daily	Not applicable
Southern Power
Cash equivalents:
Money market funds	$	80	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.

167

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

The commingled funds in Georgia Power's nuclear decommissioning trusts are invested primarily in a diversified portfolio, including, but not limited to, commercial paper, notes, repurchase agreements, and other evidences of indebtedness with a maturity not exceeding 13 months from the date of purchase. The commingled funds will, however, generally maintain a dollar-weighted average portfolio maturity of 90 days or less. The assets may be longer term investment grade fixed income obligations with maturity shortening provisions. The primary objective for the commingled funds is a high level of current income consistent with stability of principal and liquidity. Included in commingled funds as of September 30, 2014 is $5 million representing the investment of cash collateral received under the Funds' managers' securities lending program that can only be sold upon the return of the loaned securities. The money market fund within Georgia Power's nuclear decommissioning trusts represents the short-term investment of the trusts' excess cash with the goal of providing the highest possible level of income while preserving capital and maintaining liquidity. The fund's positions are in high-quality, short-term, liquid money market instruments including, but not limited to, commercial paper, floating and variable rate demand notes, debt securities issued or guaranteed by the U.S. government and its agencies, time deposits, repurchase agreements, municipal obligations, and other high-quality, short-term debt securities. The fund maintains a dollar-weighted average maturity of 60 days or less and is regulated by, and subject to, the money market regulatory requirements set by the SEC. Redemptions are available on a same day basis up to the full amount of the investment in the fund. See Note 1 to the financial statements of Southern Company and Georgia Power under "Nuclear Decommissioning" in Item 8 of the Form 10-K for additional information.

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

Southern Company, Alabama Power, and Georgia Power continue to elect the option to fair value investment securities held in the nuclear decommissioning trust funds. For the three and nine months ended September 30, 2014, the change in fair value of the funds, including reinvested interest and dividends reduced by the funds' expenses, decreased by $13 million and increased by $70 million, respectively, at Southern Company. For the three and nine months ended September 30, 2014, Alabama Power recorded a decrease in fair value of $8 million and an increase of $39 million, respectively, as an increase in regulatory liabilities. Georgia Power recorded a decrease in fair value of $5 million and an increase of $31 million, respectively, as a reduction of its regulatory asset related to its ARO.

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

168

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

As of September 30, 2014, other financial instruments for which the carrying amount did not equal fair value were as follows:

	Carrying Amount		Fair Value
	(in millions)
Long-term debt:
Southern Company	$	23,936	$	25,318
Alabama Power	$	6,625	$	7,195
Georgia Power	$	9,597	$	10,167
Gulf Power	$	1,444	$	1,517
Mississippi Power	$	2,365	$	2,397
Southern Power	$	1,629	$	1,745

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 September 30, 2014	Three Months Ended September 30, 2013	Nine Months Ended September 30, 2014	Nine Months Ended September 30, 2013
	(in millions)
As reported shares	898	878	894	874
Effect of options and performance share award units	4	3	4	5
Diluted shares	902	881	898	879

Stock options and performance share award units that were not included in the diluted earnings per share calculation because they were anti-dilutive were 16 million and 17 million for the three and nine months ended September 30, 2014, respectively, and were 16 million and 1 million for the three and nine months ended September 30, 2013.

169

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(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	—	—		1,680			—		1,680
Other comprehensive income (loss)	—	—		6			—		6
Treasury stock re-issued	—	4,996		225			—		225
Stock issued	7,781	—		332			—		332
Stock repurchased, at cost	—	—		(5		)	—		(5		)
Cash dividends on common stock	—	—		(1,390		)	—		(1,390		)
Other	—	(51	)	1			—		1
Balance at September 30, 2014	900,514	(702	)	$	19,857		$	756	$	20,613
Balance at December 31, 2012	877,803	(10,035	)	$	18,297		$	707	$	19,004
Net income after dividends on preferred and preference stock	—	—		1,230			—		1,230
Other comprehensive income (loss)	—	—		11			—		11
Treasury stock re-issued	—	1,956		89			—		89
Stock issued	12,046	—		484			49		533
Stock repurchased, at cost	—	—		(19		)	—		(19		)
Cash dividends on common stock	—	—		(1,314		)	—		(1,314		)
Other	—	(30	)	—			—		—
Balance at September 30, 2013	889,849	(8,109	)	$	18,778		$	756	$	19,534

170

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

(E) FINANCING

Bank Credit Arrangements

Bank credit arrangements provide liquidity support to the registrants' commercial paper borrowings and the traditional operating companies' variable rate pollution control revenue bonds. The amount of variable rate pollution control revenue bonds requiring liquidity support as of September 30, 2014 was approximately $1.8 billion. In addition, at September 30, 2014, the traditional operating companies had $423 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. In addition, $98 million of certain pollution control revenue bonds of Georgia Power have been reclassified to securities due within one year in anticipation of redemption in connection with unit retirement decisions. See Note 3 to the financial statements of Southern Company and Georgia Power under "Retail Regulatory Matters – Georgia Power – Integrated Resource Plans" and "Retail Regulatory Matters – Integrated Resource Plans," respectively, in Item 8 of the Form 10-K for additional information.

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

	Expires														Executable Term Loans				Due Within One Year
Company	2014		2015		2016		2017		2018		Total		Unused		One Year		Two Years		Term Out		No Term Out
	(in millions)										(in millions)				(in millions)				(in millions)
Southern Company	$	—	$	—	$	—	$	—	$	1,000	$	1,000	$	1,000	$	—	$	—	$	—	$	—
Alabama Power	70		158		50		—		1,030		1,308		1,308		58		—		58		170
Georgia Power	—		—		150		—		1,600		1,750		1,736		—		—		—		—
Gulf Power	20		60		165		30		—		275		275		50		—		50		30
Mississippi Power	15		120		165		—		—		300		300		25		40		65		70
Southern Power	—		—		—		—		500		500		499		—		—		—		—
Other	—		70		—		—		—		70		70		20		—		20		50
Total	$	105	$	408	$	530	$	30	$	4,130	$	5,203	$	5,188	$	153	$	40	$	193	$	320

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

171

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Financing Activities

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

Company	Senior Note Issuances		Senior Note Maturities		Revenue Bond Issuances and Remarketings of Purchased Bonds(a)		Revenue Bond Redemptions		Other Long-Term Debt Issuances			Other Long-Term Debt Redemptions(b)
	(in millions)
Southern Company	$	750	$	350	$	—	$	—	$	—		$	—
Alabama Power	400		—		—		—		—			—
Georgia Power	—		—		40		37		1,000			4
Gulf Power	200		—		42		29		—			—
Mississippi Power	—		—		—		—		493			222
Southern Power	—		—		—		—		10			1
Other	—		—		—		—		—			15
Elimination(c)	—		—		—		—		(220		)	(220		)
Total	$	1,350	$	350	$	82	$	66	$	1,283		$	22

(a) Includes remarketing by Gulf Power of $13 million aggregate principal amount of revenue bonds previously purchased and held by Gulf Power since December 2013 and remarketing by Georgia Power of $40 million aggregate principal amount of revenue bonds previously purchased and held by Georgia Power since 2010.

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

(c) Intercompany loan from Southern Company to Mississippi Power eliminated in Southern Company's Condensed Consolidated Financial Statements. This loan was repaid on September 29, 2014.

Southern Company

In August 2014, Southern Company issued $400 million aggregate principal amount of Series 2014A 1.30% Senior Notes due August 15, 2017 and $350 million aggregate principal amount of Series 2014B 2.15% Senior Notes due September 1, 2019. The proceeds were used to pay a portion of Southern Company's outstanding short-term indebtedness and for other general corporate purposes.

Alabama Power

In August 2014, Alabama Power issued $400 million aggregate principal amount of Series 2014A 4.150% Senior Notes due August 15, 2044. The proceeds were used for general corporate purposes, including Alabama Power's continuous construction program.

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

172

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

$1.0 billion. Georgia Power's reimbursement obligations to the DOE are full recourse and also secured by a first priority lien on (i) Georgia Power's 45.7% undivided ownership interest in Plant Vogtle Units 3 and 4 (primarily the units under construction, the related real property, and any nuclear fuel loaded in the reactor core) and (ii) Georgia Power's rights and obligations under the principal contracts relating to Plant Vogtle Units 3 and 4. The interest rate applicable to $500 million of the initial advance under the FFB Credit Facility is 3.860% for an interest period that extends to 2044 and the interest rate applicable to the remaining $500 million is 3.488% for an interest period that extends to 2029, and is expected to be reset from time to time thereafter through 2044. In connection with its entry into the agreements with the DOE and the FFB, 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.

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

Gulf Power

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

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

In September 2014, Gulf Power issued $200 million aggregate principal amount of Series 2014A 4.55% Senior Notes due October 1, 2044. The proceeds were used to repay a portion of its outstanding short-term indebtedness, for general corporate purposes, including Gulf Power's continuous construction program, and subsequent to September 30, 2014, for repayment at maturity $75 million aggregate principal amount of Gulf Power's Series K 4.90% Senior Notes due October 1, 2014.

Mississippi Power

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 January 2014 and subsequent to September 30, 2014, Mississippi Power received an additional $75 million and $50 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. See Note 3 to the financial statements of Southern Company and Mississippi Power in Item 8 of the Form 10-K under "Integrated Coal Gasification Combined Cycle – Proposed Sale of Undivided Interest to SMEPA" for additional information.

As reflected in the table above in "Other Long-Term Debt Issuances," in May 2014, Mississippi Power issued a 19-month floating rate promissory note to Southern Company for a loan bearing interest based on one-month LIBOR. This loan was for $220 million aggregate principal amount and the proceeds were used for working capital and other general corporate purposes, including Mississippi Power's construction program. This loan was repaid on September 29, 2014.

In May 2014 and August 2014, the MBFC issued $12.3 million and $10.5 million, respectively, aggregate principal amount of MBFC Taxable Revenue Bonds (Mississippi Power Company Project), Series 2013A for the benefit of

173

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Mississippi Power and proceeds were used to reimburse Mississippi Power for the cost of the acquisition, construction, equipping, installation, and improvement of certain equipment and facilities for the lignite mining facility related to the Kemper IGCC. Any future issuances of the Series 2013A bonds will be used for this same purpose.

Southern Power

During the nine months ended September 30, 2014, Southern Power prepaid $0.8 million of long-term debt payable to Turner Renewable Energy, LLC (TRE) and issued $3.9 million due April 30, 2034, $5.3 million due May 31, 2034, $0.8 million due April 30, 2033, and an additional $0.1 million due June 15, 2032 under promissory notes payable to TRE related to the financing of Adobe Solar, LLC (Adobe), Macho Springs Solar, LLC (Macho Springs), Campo Verde Solar, LLC, and Apex Nevada Solar, LLC, respectively.

(F) RETIREMENT BENEFITS

Southern Company has a defined benefit, trusteed, pension plan covering substantially all employees. The qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended. No mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2014. Southern Company also provides certain defined benefit pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, Southern Company provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The traditional operating companies fund related other postretirement trusts to the extent required by their respective regulatory commissions.

See Note 2 to the financial statements of Southern Company, Alabama Power, Georgia Power, Gulf Power, and Mississippi Power in Item 8 of the Form 10-K for additional information.

174

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

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

Pension Plans	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power
	(in millions)
Three Months Ended September 30, 2014
Service cost	$	53		$	12		$	16		$	4		$	3
Interest cost	109			26			39			4			5
Expected return on plan assets	(161		)	(42		)	(57		)	(7		)	(8		)
Amortization:
Prior service costs	6			2			2			—			—
Net (gain)/loss	28			7			10			1			2
Net cost	$	35		$	5		$	10		$	2		$	2
Nine Months Ended September 30, 2014
Service cost	$	160		$	36		$	47		$	8		$	8
Interest cost	326			78			115			14			15
Expected return on plan assets	(484		)	(126		)	(170		)	(21		)	(22		)
Amortization:
Prior service costs	19			5			7			1			1
Net (gain)/loss	83			23			30			3			4
Net cost	$	104		$	16		$	29		$	5		$	6
Three Months Ended September 30, 2013
Service cost	$	58		$	12		$	17		$	3		$	3
Interest cost	97			23			35			4			5
Expected return on plan assets	(151		)	(39		)	(54		)	(6		)	(7		)
Amortization:
Prior service costs	7			2			3			—			1
Net (gain)/loss	50			13			19			2			2
Net cost	$	61		$	11		$	20		$	3		$	4
Nine Months Ended September 30, 2013
Service cost	$	174		$	39		$	52		$	8		$	8
Interest cost	291			69			104			13			14
Expected return on plan assets	(452		)	(117		)	(160		)	(19		)	(20		)
Amortization:
Prior service costs	20			5			8			1			1
Net (gain)/loss	150			39			56			6			7
Net cost	$	183		$	35		$	60		$	9		$	10

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Postretirement Benefits	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power
	(in millions)
Three Months Ended September 30, 2014
Service cost	$	5		$	1		$	2		$	—		$	—
Interest cost	19			5			9			—			—
Expected return on plan assets	(14		)	(6		)	(6		)	—			—
Amortization:
Prior service costs	1			1			—			—			—
Net (gain)/loss	1			—			—			—			—
Net cost	$	12		$	1		$	5		$	—		$	—
Nine Months Ended September 30, 2014
Service cost	$	16		$	4		$	5		$	1		$	1
Interest cost	59			15			26			2			2
Expected return on plan assets	(44		)	(19		)	(19		)	(1		)	(1		)
Amortization:
Prior service costs	3			3			—			—			—
Net (gain)/loss	2			—			1			—			—
Net cost	$	36		$	3		$	13		$	2		$	2
Three Months Ended September 30, 2013
Service cost	$	6		$	2		$	3		$	—		$	—
Interest cost	18			5			8			1			1
Expected return on plan assets	(14		)	(6		)	(7		)	(1		)	—
Amortization:
Transition obligation	2			—			1			—			—
Prior service costs	1			1			—			—			—
Net (gain)/loss	3			—			2			—			—
Net cost	$	16		$	2		$	7		$	—		$	1
Nine Months Ended September 30, 2013
Service cost	$	18		$	5		$	6		$	1		$	1
Interest cost	55			14			24			2			3
Expected return on plan assets	(42		)	(18		)	(19		)	(1		)	(1		)
Amortization:
Transition obligation	4			—			3			—			—
Prior service costs	3			3			—			—			—
Net (gain)/loss	9			1			6			—			—
Net cost	$	47		$	5		$	20		$	2		$	3

176

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

(G) EFFECTIVE TAX RATE AND UNRECOGNIZED TAX BENEFITS

Effective Tax Rate

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

Southern Company

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

Southern Company's effective tax rate was 33.9% for the nine months ended September 30, 2014 compared to 33.9% for the corresponding period in 2013. The effective tax rate was impacted by the offsetting increases resulting from higher net income and less benefit related to investment tax credits, and decreases resulting from more non-taxable AFUDC equity, changes in state apportionment, and beneficial changes in certain state income tax laws.

Alabama Power

Alabama Power's effective tax rate was 39.0% for the nine months ended September 30, 2014 compared to 39.3% for the corresponding period in 2013.

Georgia Power

Georgia Power's effective tax rate was 37.2% for the nine months ended September 30, 2014 compared to 38.0% for the corresponding period in 2013.

Gulf Power

Gulf Power's effective tax rate was 37.4% for the nine months ended September 30, 2014 compared to 37.6% for the corresponding period in 2013.

Mississippi Power

Mississippi Power's effective tax rate was (45.5)% for the nine months ended September 30, 2014 compared to (42.1)% for the corresponding period in 2013. The change in the tax benefit was primarily due to an increase in non-taxable AFUDC equity related to the construction of the Kemper IGCC, partially offset by a lower net loss for the current period compared to the corresponding period in 2013.

Southern Power

Southern Power's effective tax rate was 14.4% for the nine months ended September 30, 2014 compared to 20.5% for the corresponding period in 2013. The decrease was primarily due to the impact of state apportionment changes which reduced Southern Power's deferred tax liabilities, a change in filing method for North Carolina income tax, an increase in state income tax credits, and beneficial changes in certain state income tax laws. The decrease was partially offset by less federal income tax benefit related to investment tax credits in the current year.

Unrecognized Tax Benefits

For the 2013 tax year, Southern Company included in its consolidated federal income tax return a deduction for R&E expenditures related to the Kemper IGCC. The Kemper IGCC is based on first-of-a-kind technology, and Mississippi Power and Southern Company believe that a significant portion of the plant costs qualify as deductible R&E under Internal Revenue Code Section 174. The IRS is currently reviewing the underlying support for the deduction, but has not completed its audit of these expenditures. Due to the uncertainty related to this tax position, Mississippi Power and Southern Company recorded an unrecognized tax benefit of approximately $100 million and associated interest of $2 million as of September 30, 2014.

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

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

(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. See Note (C) herein for additional information. In the statements of cash flows, the cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities and the cash impacts of settled foreign currency derivatives are recorded as investing activities.

Energy-Related Derivatives

The traditional operating companies and Southern Power enter into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the traditional operating companies have limited exposure to market volatility in commodity fuel prices and prices of electricity. Each of the traditional operating companies manages fuel-hedging programs, implemented per the guidelines of their respective state PSCs, through the use of financial derivative contracts, which is expected to continue to mitigate price volatility. The traditional operating companies (with respect to wholesale generating capacity) and Southern Power have limited exposure to market volatility in commodity fuel prices and prices of electricity because their long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, Southern Power has been and may continue to be exposed to market volatility in energy-related commodity prices as a result of sales from its uncontracted generating capacity. Further, the traditional operating companies may be exposed to market volatility in energy-related commodity prices to the extent any uncontracted wholesale generating capacity is used to sell electricity.

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.

178

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

At September 30, 2014, the net volume of energy-related derivative contracts for natural gas positions for the Southern Company system, together with the longest hedge date over which the respective entity is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest non-hedge date for derivatives not designated as hedges, were as follows:

	Net Purchased mmBtu	Longest Hedge Date	Longest Non-Hedge Date
	(in millions)
Southern Company	232	2018	2017
Alabama Power	57	2017	—
Georgia Power	47	2017	—
Gulf Power	77	2018	—
Mississippi Power	49	2017	—
Southern Power	2	—	2017

In addition to the volumes discussed in the above table, the traditional operating companies and Southern Power enter into physical natural gas supply contracts that provide the option to sell back excess gas due to operational constraints. The maximum expected volume of natural gas subject to such a feature is 7 million mmBtu for Southern Company, 1 million mmBtu for Alabama Power, 4 million mmBtu for Georgia Power, and 1 million mmBtu for Southern Power.

For cash flow hedges, the amounts expected to be reclassified from accumulated OCI to earnings for the next 12-month period ending September 30, 2015 are immaterial for all registrants.

Interest Rate Derivatives

Southern Company and certain subsidiaries may also enter into interest rate derivatives to hedge exposure to changes in interest rates. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings, with any ineffectiveness recorded directly to earnings. Derivatives related to existing fixed rate securities are accounted for as fair value hedges, where the derivatives' fair value gains or losses and hedged items' fair value gains or losses are both recorded directly to earnings, providing an offset, with any difference representing ineffectiveness.

At September 30, 2014, the following interest rate derivatives were outstanding:

	Notional Amount		Interest Rate Received	Weighted Average Interest Rate Paid	Hedge Maturity Date	Fair Value Gain (Loss) September 30, 2014
	(in millions)					(in millions)
Cash flow hedges of forecasted debt
Alabama Power	$	100	3-month LIBOR	3.07%	October 2025	$	(1	)
Fair value hedges on existing debt
Southern Company	250		1.30%	3-month LIBOR + 0.17%	August 2017	(1		)
Total	$	350				$	(2	)

179

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Subsequent to September 30, 2014, Alabama Power entered into forward-starting interest rate swaps to hedge exposure to interest rate changes related to an anticipated debt issuance. The notional amount of the swaps totaled $100 million.

Subsequent to September 30, 2014, Georgia Power entered into interest rate swaps to hedge exposure to interest rate changes related to existing debt. The notional amounts of the swaps totaled $900 million.

The estimated pre-tax gains (losses) that will be reclassified from accumulated OCI to interest expense for the next 12-month period ending September 30, 2015 are immaterial for all registrants. Southern Company and certain subsidiaries have deferred gains and losses that are expected to be amortized into earnings through 2037.

Foreign Currency Derivatives

Southern Company and certain subsidiaries may enter into foreign currency derivatives to hedge exposure to changes in foreign currency exchange rates arising from purchases of equipment denominated in a currency other than U.S. dollars. Derivatives related to a firm commitment in a foreign currency transaction are accounted for as fair value hedges where the derivatives' fair value gains or losses and the hedged items' fair value gains or losses are both recorded directly to earnings. Derivatives related to a forecasted transaction are accounted for as cash flow hedges where the effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. Any ineffectiveness is recorded directly to earnings; however, Mississippi Power has regulatory approval allowing it to defer any ineffectiveness associated with firm commitments related to the Kemper IGCC to a regulatory asset.

At September 30, 2014, there were no foreign currency derivatives outstanding.

Derivative Financial Statement Presentation and Amounts

At September 30, 2014, the fair value of energy-related derivatives (excluding regulatory hedges) was immaterial. At September 30, 2014, the fair value of energy-related derivatives designated as hedging instruments for regulatory purposes and interest rate derivatives was reflected in the balance sheets as follows:

Asset Derivatives at September 30, 2014
	Fair Value
Derivative Category and Balance Sheet Location	Southern Company		Alabama Power		Georgia Power		Gulf Power		Mississippi Power		Southern Power
	(in millions)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets	$	9	$	4	$	1	$	2	$	2
Other deferred charges and assets	2		1		—		1		—
Total derivatives designated as hedging instruments for regulatory purposes	$	11	$	5	$	1	$	3	$	2	N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current assets	$	2	$	—	$	—	$	—	$	—	$	—
Total asset derivatives	$	13	$	5	$	1	$	3	$	2	$	—

180

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Liability Derivatives at September 30, 2014
	Fair Value
Derivative Category and Balance Sheet Location	Southern Company		Alabama Power		Georgia Power		Gulf Power		Mississippi Power		Southern Power
	(in millions)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Liabilities from risk management activities (a)	$	27	$	5	$	10	$	7	$	5
Other deferred credits and liabilities	25		6		2		12		5
Total derivatives designated as hedging instruments for regulatory purposes	$	52	$	11	$	12	$	19	$	10	N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other deferred credits and liabilities	$	4	$	1	$	—	$	—	$	—	$	—
Total liability derivatives	$	56	$	12	$	12	$	19	$	10	$	—

(a) Georgia Power includes liabilities from risk management activities in other current liabilities.

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

181

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

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 (a)	$	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

(a) Georgia Power includes liabilities from risk management activities in other current liabilities.

The derivative contracts of Southern Company, the traditional operating companies, and Southern Power are not subject to master netting arrangements or similar agreements and are reported gross on each registrant's financial statements. Some of these energy-related and interest rate derivative contracts may contain certain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. Amounts related to energy-related derivative contracts at September 30, 2014 and December 31, 2013 are presented in the following tables. Interest rate derivatives presented in the tables above do not have amounts available for offset and are therefore excluded from the offsetting disclosure tables below.

Derivative Contracts at September 30, 2014
	Fair Value
	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power			Southern Power
	(in millions)
Assets
Energy-related derivatives:
Energy-related derivatives presented in the Balance Sheet (a)	$	12		$	5		$	1		$	3		$	2		$	1
Gross amounts not offset in the Balance Sheet (b)	(11		)	(4		)	(1		)	(3		)	(2		)	—
Net energy-related derivative assets	$	1		$	1		$	—		$	—		$	—		$	1
Liabilities
Energy-related derivatives:
Energy-related derivatives presented in the Balance Sheet (a)	$	53		$	11		$	12		$	19		$	10		$	1
Gross amounts not offset in the Balance Sheet (b)	(11		)	(4		)	(1		)	(3		)	(2		)	—
Net energy-related derivative liabilities	$	42		$	7		$	11		$	16		$	8		$	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.

182

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Derivative Contracts at December 31, 2013
	Fair Value
	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power			Southern Power
	(in millions)
Assets
Energy-related derivatives:
Energy-related derivatives presented in the Balance Sheet (a)	$	24		$	7		$	5		$	7		$	5		$	1
Gross amounts not offset in the Balance Sheet (b)	(22		)	(5		)	(5		)	(6		)	(4		)	—
Net energy-related derivative assets	$	2		$	2		$	—		$	1		$	1		$	1
Liabilities
Energy-related derivatives:
Energy-related derivatives presented in the Balance Sheet (a)	$	56		$	8		$	21		$	17		$	10		$	1
Gross amounts not offset in the Balance Sheet (b)	(22		)	(5		)	(5		)	(6		)	(4		)	—
Net energy-related derivative liabilities	$	34		$	3		$	16		$	11		$	6		$	1

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

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

At September 30, 2014 and December 31, 2013, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred on the balance sheets were as follows:

Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet at September 30, 2014
Derivative Category and Balance Sheet Location	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power
	(in millions)
Energy-related derivatives:
Other regulatory assets, current	$	(27	)	$	(5	)	$	(10	)	$	(7	)	$	(5	)
Other regulatory assets, deferred	(25		)	(6		)	(2		)	(12		)	(5		)
Other regulatory liabilities, current	9			4			1			2			2
Other regulatory liabilities, deferred (a)	2			1			—			1			—
Total energy-related derivative gains (losses)	$	(41	)	$	(6	)	$	(11	)	$	(16	)	$	(8	)

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

183

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet at December 31, 2013
Derivative Category and Balance Sheet Location	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power
	(in millions)
Energy-related derivatives:
Other regulatory assets, current	$	(26	)	$	(3	)	$	(13	)	$	(6	)	$	(4	)
Other regulatory assets, deferred	(29		)	(5		)	(8		)	(11		)	(6		)
Other regulatory liabilities, current	16			5			3			5			3
Other regulatory liabilities, deferred (a)	7			2			2			2			2
Total energy-related derivative gains (losses)	$	(32	)	$	(1	)	$	(16	)	$	(10	)	$	(5	)

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

For the three and nine months ended September 30, 2014 and 2013, the pre-tax effects of interest rate and foreign currency derivatives designated as fair value hedging instruments on the statements of income were immaterial on a gross basis for all registrants. Furthermore, the pre-tax effects of interest rate derivatives designated as fair value hedging instruments on the statements of income were offset by changes to the carrying value of long-term debt and the pre-tax effects of foreign currency derivatives designated as fair value hedging instruments on the statements of income were offset by changes in the fair value of the purchase commitment related to equipment purchases.

For the three and nine months ended September 30, 2014 and 2013, the pre-tax effects of energy-related derivatives and interest rate derivatives designated as cash flow hedging instruments recognized in OCI and those reclassified from accumulated OCI into earnings were immaterial for all registrants.

There was no material ineffectiveness recorded in earnings for any registrant for any period presented.

For the three and nine months ended September 30, 2014 and 2013, the pre-tax effects of energy-related and foreign currency derivatives not designated as hedging instruments on the statements of income were immaterial for all registrants.

For Southern Power's energy-related derivatives not designated as hedging instruments, a portion of the pre-tax realized and unrealized gains and losses was associated with hedging fuel price risk of certain PPA customers and had no impact on net income or on fuel expense as presented in Southern Company's and Southern Power's statements of income for the three and nine months ended September 30, 2014 and 2013. This third party hedging activity has been discontinued.

Contingent Features

The registrants do not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain Southern Company subsidiaries. At September 30, 2014, the registrants' collateral posted with their derivative counterparties was immaterial.

At September 30, 2014, the fair value of derivative liabilities with contingent features was $26 million for all registrants. The maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, were $26 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

184

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

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 from Sun Edison, LLC, the original developer of the project. Adobe constructed and owns an approximately 20-MW solar photovoltaic facility in Kern County, California. The solar facility began commercial operation on May 21, 2014 and the entire output of the plant is contracted under a 20-year PPA with Southern California Edison Company. The acquisition was in accordance with Southern Power's overall growth strategy.

Southern Power's acquisition of Adobe included cash consideration of approximately $96.2 million. The fair values of the assets, liabilities, and intangibles acquired were recorded as follows: $83.5 million to property, plant, and equipment, $14.5 million to receivables related to reimbursable transmission costs and $6.3 million to PPA intangible, resulting in a $5.1 million bargain purchase gain with a $2.9 million deferred tax liability. The bargain purchase gain is included in other income (expense), net in Southern Company's and Southern Power's Condensed Consolidated Statements of Income herein. Acquisition-related costs were expensed as incurred and were not material.

Macho Springs Solar, LLC

On May 22, 2014, Southern Power and TRE, through STR, acquired all of the outstanding membership interests ofMacho Springs from First Solar Development, LLC, the original developer of the project. Macho Springs constructed and owns an approximately50-MW solar photovoltaic facility in Luna County, New Mexico. The solar facility began commercial operation on May 23,2014and the entire output of the plant is contracted under a20-year PPA withEl Paso Electric Company. The acquisition was in accordance with Southern Power's overall growth strategy.

Southern Power's acquisition of Macho Springs included cash consideration of approximately $130.0 million. As of September 30, 2014, the fair value of the assets acquired was recorded primarily as property, plant, and equipment; however, the allocation of the purchase price to individual assets has not been finalized. The acquisition did not include any contingent consideration. Acquisition-related costs were expensed as incurred and were not material.

SG2 Imperial Valley, LLC

Subsequent to September 30, 2014, Southern Power, through its wholly-owned subsidiary SG2 Holdings, LLC (Holdings), acquired all of the outstanding membership interests of SG2 Imperial Valley, LLC (SG2) from a wholly-owned subsidiary of First Solar, Inc. (First Solar), the developer of the project. SG2 is constructing an approximately 150-MW solar photovoltaic facility in Southern California (Imperial Facility), which is expected to begin commercial operation later in the fourth quarter 2014. The Imperial Facility's output is contracted under a 25-year PPA with San Diego Gas & Electric Company, a subsidiary of Sempra Energy. This PPA will be accounted for as an operating lease. The acquisition of the Imperial Facility aligns with Southern Power's overall growth strategy.

In connection with this acquisition, Holdings made an aggregate payment (consisting of cash consideration and a secured promissory note) of approximately $128 million to the subsidiary of First Solar and became obligated to pay the contract price as it becomes due under the construction contract for the Imperial Facility. The allocation of

185

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

the purchase price to individual assets has not been finalized. In addition, subject to certain terms and conditions, a subsidiary of First Solar will be admitted as a minority member of Holdings, and as the members of Holdings will make additional agreed upon capital contributions to Holdings that will be used to pay off the previously issued secured promissory note and to fund the Imperial Facility's construction costs. As a result of these capital contributions, the aggregate purchase price payable by Southern Power for the acquisition is approximately $508 million. Following these capital contributions, Southern Power will indirectly own 100% of the class A membership interests of Holdings and be entitled to 51% of all cash distributions from Holdings, and First Solar will indirectly own 100% of the class B membership interests of Holdings and be entitled to 49% of all cash distributions from Holdings. In addition, Southern Power will be entitled to substantially all of the federal tax benefits with respect to this transaction.

If the Imperial Facility does not achieve substantialcompletion by a certain date, Southern Power may require that First Solar make a rescission payment to Southern Power in an amount equal to Southern Power's investment in Holdings, and Southern Power would be required to transfer its ownership interests in SG2 back to First Solar (the Rescission Payment and Transfer).

The ultimate outcome of this matter cannot be determined at this time; however, Holdings believes the likelihood of the Rescission Payment and Transfer to be remote at the acquisition date.

186

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

(J) SEGMENT AND RELATED INFORMATION

The primary business of the Southern Company system is electricity sales by the traditional operating companies and Southern Power. The four traditional operating companies – Alabama Power, Georgia Power, Gulf Power, and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market.

Southern Company's reportable business segments are the sale of electricity by the four traditional operating companies and Southern Power. Revenues from sales by Southern Power to the traditional operating companies were $103 million and $243 million for the three and nine months ended September 30, 2014, respectively, and $97 million and $264 million for the three and nine months ended September 30, 2013, respectively. The "All Other" column includes parent Southern Company, which does not allocate operating expenses to business segments. Also, this category includes segments below the quantitative threshold for separate disclosure. These segments include investments in telecommunications and leveraged lease projects. All other inter-segment revenues are not material. Financial data for business segments and products and services for the three and nine months ended September 30, 2014 and 2013 was as follows:

	Electric Utilities
	Traditional Operating Companies		Southern Power		Eliminations			Total		All Other			Eliminations			Consolidated
	(in millions)
Three Months Ended September 30, 2014:
Operating revenues	$	5,007	$	435	$	(115	)	$	5,327	$	34		$	(22	)	$	5,339
Segment net income (loss)(a)(b)	658		64		—			722		(2		)	(2		)	718
Nine Months Ended September 30, 2014:
Operating revenues	$	13,594	$	1,115	$	(301	)	$	14,408	$	114		$	(72	)	$	14,450
Segment net income (loss)(a)(c)	1,557		128		—			1,685		—			(5		)	1,680
Total assets at September 30, 2014	$	62,419	$	4,609	$	(166	)	$	66,862	$	1,304		$	(512	)	$	67,654
Three Months Ended September 30, 2013:
Operating revenues	$	4,744	$	365	$	(104	)	$	5,005	$	35		$	(23	)	$	5,017
Segment net income (loss)(a)(b)	765		85		—			850		(1		)	3			852
Nine Months Ended September 30, 2013:
Operating revenues	$	12,430	$	975	$	(285	)	$	13,120	$	108		$	(68	)	$	13,160
Segment net income (loss)(a)(c)	1,099		142		—			1,241		(12		)	1			1,230
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 September 30, 2014 and September 30, 2013 includes a $418.0 million pre-tax charge ($258.1 million after tax) and a $150.0 million pre-tax charge ($92.6 million after tax), respectively, for estimated probable losses on the Kemper IGCC. See Note (B) under "Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" herein for additional information.

(c) Segment net income (loss) for the traditional operating companies for the nine months ended September 30, 2014 and September 30, 2013 includes $798.0 million in pre-tax charges ($492.8 million after tax) and $1.14 billion in pre-tax charges ($704.0 million after tax), respectively, for estimated probable losses on the Kemper IGCC. See Note (B) under "Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" herein for additional information.

187

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Products and Services

	Electric Utilities' Revenues
Period	Retail		Wholesale		Other		Total
	(in millions)
Three Months Ended September 30, 2014	$	4,558	$	600	$	169	$	5,327
Three Months Ended September 30, 2013	4,319		520		166		5,005
Nine Months Ended September 30, 2014	$	12,186	$	1,719	$	503	$	14,408
Nine Months Ended September 30, 2013	11,237		1,406		477		13,120

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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.

(4) Instruments Describing Rights of Security Holders, Including Indentures
Southern Company
(a)1	-	Ninth Supplemental Indenture to the Senior Note Indenture dated as of August 22, 2014, providing for the issuance of the Series 2014A 1.30% Senior Notes due August 15, 2017. (Designated in Form 8-K dated August 19, 2014, File No. 1-3526, as Exhibit 4.2(a).)
(a)2	-	Tenth Supplemental Indenture to the Senior Note Indenture dated as of August 22, 2014, providing for the issuance of the Series 2014B 2.15% Senior Notes due September 1, 2019. (Designated in Form 8-K dated August 19, 2014, File No. 1-3526, as Exhibit 4.2(b).)
Alabama Power
(b)1	-	Fifty-Second Supplemental Indenture to the Senior Note Indenture dated as of August 26, 2014, providing for the issuance of the Series 2014A 4.150% Senior Notes due August 15, 2044. (Designated in Form 8-K dated August 20, 2014, File No. 1-3164, as Exhibit 4.6.)
Gulf Power
(d)1	-	Twenty-First Supplemental Indenture to the Senior Note Indenture dated as of September 23, 2014, providing for the issuance of the Series 2014A 4.55% Senior Notes due October 1, 2044. (Designated in Form 8-K dated September 16, 2014, File No. 001-31737, as Exhibit 4.2.)
(24) Power of Attorney and Resolutions
Southern Company
(a)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2013, File No. 1-3526 as Exhibit 24(a) and incorporated herein by reference.)
Alabama Power
(b)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2013, File No. 1-3164 as Exhibit 24(b) and incorporated herein by reference.)
(b)2	-	Power of Attorney for Mark A. Crosswhite. (Designated in the Form 10-Q for the quarter ended March 31, 2014, File No. 1-3164 as Exhibit 24(b)2 and incorporated herein by reference.)
Georgia Power
(c)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2013, File No. 1-6468 as Exhibit 24(c) and incorporated herein by reference.)

189

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.
(f)2	-	Certificate of Southern Power's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

190

(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

191

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: November 6, 2014

192

ALABAMA POWER COMPANY

SIGNATURES

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

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

Date: November 6, 2014

193

GEORGIA POWER COMPANY

SIGNATURES

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

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

Date: November 6, 2014

194

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: November 6, 2014

195

MISSISSIPPI POWER COMPANY

SIGNATURES

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

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

Date: November 6, 2014

196

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: November 6, 2014

197