10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

þQUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2016

OR

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

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

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

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

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

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

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

Registrant	Description of Common Stock	Shares Outstanding at March 31, 2016
The Southern Company	Par Value $5 Per Share	918,258,425
Alabama Power Company	Par Value $40 Per Share	30,537,500
Georgia Power Company	Without Par Value	9,261,500
Gulf Power Company	Without Par Value	5,642,717
Mississippi Power Company	Without Par Value	1,121,000
Southern Power Company	Par Value $0.01 Per Share	1,000

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

2

INDEX TO QUARTERLY REPORT ON FORM 10-Q

March 31, 2016

		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	36
	Condensed Statements of Comprehensive Income	36
	Condensed Statements of Cash Flows	37
	Condensed Balance Sheets	38
	Management's Discussion and Analysis of Financial Condition and Results of Operations	40
	Georgia Power Company
	Condensed Statements of Income	51
	Condensed Statements of Comprehensive Income	51
	Condensed Statements of Cash Flows	52
	Condensed Balance Sheets	53
	Management's Discussion and Analysis of Financial Condition and Results of Operations	55
	Gulf Power Company
	Condensed Statements of Income	69
	Condensed Statements of Comprehensive Income	69
	Condensed Statements of Cash Flows	70
	Condensed Balance Sheets	71
	Management's Discussion and Analysis of Financial Condition and Results of Operations	73
	Mississippi Power Company
	Condensed Statements of Income	85
	Condensed Statements of Comprehensive Income	85
	Condensed Statements of Cash Flows	86
	Condensed Balance Sheets	87
	Management's Discussion and Analysis of Financial Condition and Results of Operations	89
	Southern Power Company and Subsidiary Companies
	Condensed Consolidated Statements of Income	110
	Condensed Consolidated Statements of Comprehensive Income	110
	Condensed Consolidated Statements of Cash Flows	111
	Condensed Consolidated Balance Sheets	112
	Management's Discussion and Analysis of Financial Condition and Results of Operations	114
	Notes to the Condensed Financial Statements	124
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	34
Item 4.	Controls and Procedures	34

3

INDEX TO QUARTERLY REPORT ON FORM 10-Q

March 31, 2016

		Page Number
	PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	166
Item 1A.	Risk Factors	166
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	166
	Signatures	169

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 in 2013 for Georgia Power for the years 2014 through 2016 and subsequently extended through 2019
AFUDC	Allowance for funds used during construction
AGL Resources	AGL Resources Inc.
Alabama Power	Alabama Power Company
ASC	Accounting Standards Codification
ASU	Accounting Standards Update
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
Bridge Agreement	Senior unsecured Bridge Credit Agreement, dated as of September 30, 2015, among Southern Company, the lenders identified therein, and Citibank, N.A.
CCR	Coal combustion residuals
Clean Air Act	Clean Air Act Amendments of 1990
CO2	Carbon dioxide
COD	Commercial operation date
Contractor	Westinghouse and its affiliate, WECTEC Global Project Services Inc. (formerly known as CB&I Stone & Webster, Inc.), formerly a subsidiary of The Shaw Group Inc. and Chicago Bridge & Iron Company N.V.
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
Eligible Project Costs	Certain costs of construction relating to Plant Vogtle Units 3 and 4 that are eligible for financing under the Title XVII Loan Guarantee Program
EPA	U.S. Environmental Protection Agency
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FFB	Federal Financing Bank
Fitch	Fitch Ratings, Inc.
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, 2015
GAAP	U.S. generally accepted accounting principles
Georgia Power	Georgia Power Company
Gulf Power	Gulf Power Company
IGCC	Integrated coal gasification combined cycle
IIC	Intercompany interchange contract
Internal Revenue Code	Internal Revenue Code of 1986, as amended
IRS	Internal Revenue Service
ITC	Investment tax credit
Kemper IGCC	IGCC facility under construction by Mississippi Power in Kemper County, Mississippi
KWH	Kilowatt-hour
LIBOR	London Interbank Offered Rate
MATS rule	Mercury and Air Toxics Standards rule
Merger	The merger of Merger Sub with and into AGL Resources on the terms and subject to the conditions set forth in the Merger Agreement, with AGL Resources continuing as the surviving corporation and a wholly-owned, direct subsidiary of Southern Company

5

DEFINITIONS

(continued)

Term	Meaning
Merger Agreement	Agreement and Plan of Merger, dated as of August 23, 2015, among Southern Company, AGL Resources, and Merger Sub
Merger Sub	AMS Corp., a wholly-owned, direct subsidiary of Southern Company
Mirror CWIP	A regulatory liability account for use in mitigating future rate impacts for Mississippi Power customers
Mississippi Power	Mississippi Power Company
mmBtu	Million British thermal units
Moody's	Moody's Investors Service, Inc.
MW	Megawatt
NCCR	Georgia Power's Nuclear Construction Cost Recovery
NRC	U.S. Nuclear Regulatory Commission
OCI	Other comprehensive income
PEP	Mississippi Power's Performance Evaluation Plan
Plant Vogtle Units 3 and 4	Two new nuclear generating units under construction at Georgia Power's Plant Vogtle
power pool	The operating arrangement whereby the integrated generating resources of the traditional operating companies and Southern Power Company (excluding subsidiaries) are subject to joint commitment and dispatch in order to serve their combined load obligations
PPA	Power purchase agreement
PSC	Public Service Commission
PTC	Production tax credit
Rate CNP	Alabama Power's Rate Certificated New Plant
Rate CNP Compliance	Alabama Power's Rate Certificated New Plant Compliance
Rate CNP PPA	Alabama Power's Rate Certificated New Plant Power Purchase Agreement
Rate RSE	Alabama Power's Rate Stabilization and Equalization plan
registrants	Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power Company
ROE	Return on equity
S&P	Standard and Poor's Ratings Services, a division of The McGraw Hill Companies, Inc.
scrubber	Flue gas desulfurization system
SEC	U.S. Securities and Exchange Commission
SMEPA	South Mississippi Electric Power Association
Southern Company	The Southern Company
Southern Company system	Southern Company, the traditional operating companies, Southern Power, Southern Electric Generating Company, Southern Nuclear, Southern Company Services, Inc. (the Southern Company system service company), Southern Communications Services, Inc., and other subsidiaries
Southern Nuclear	Southern Nuclear Operating Company, Inc.
Southern Power	Southern Power Company and its subsidiaries
traditional operating companies	Alabama Power, Georgia Power, Gulf Power, and Mississippi Power
Vogtle Owners	Georgia Power, Oglethorpe Power Corporation, the Municipal Electric Authority of Georgia, and the City of Dalton, Georgia, an incorporated municipality in the State of Georgia acting by and through its Board of Water, Light, and Sinking Fund Commissioners
Westinghouse	Westinghouse Electric Company LLC

6

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

This Quarterly Report on Form 10-Q contains forward-looking statements. Forward-looking statements include, among other things, statements concerning retail rates, the potential financing of the Merger, the expected timing of the completion of the Merger, the strategic goals for the wholesale business, economic conditions, fuel and environmental cost recovery and other rate actions, current and proposed environmental regulations and related compliance plans and estimated expenditures, pending or potential litigation matters, access to sources of capital, financing activities, completion dates of acquisitions and construction projects, filings with state and federal regulatory authorities, federal income tax benefits, estimated sales and purchases under power sale and purchase agreements, and estimated construction and other plans and expenditures. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "could," "should," "expects," "plans," "anticipates," "believes," "estimates," "projects," "predicts," "potential," or "continue" or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. These factors include:

• the impact of recent and future federal and state regulatory changes, including legislative and regulatory initiatives regarding deregulation and restructuring of the electric utility industry, environmental laws regulating emissions, discharges, and disposal to air, water, and land, 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, without limitation, IRS and state tax audits;

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

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

• available sources and costs of fuels;

• effects of inflation;

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

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

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

• advances in technology;

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

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

• actions related to cost recovery for the Kemper IGCC, including the ultimate impact of the 2015 decision of the Mississippi Supreme Court, the Mississippi PSC's December 2015 rate order, and related legal or regulatory proceedings, Mississippi PSC review of the prudence of Kemper IGCC costs and approval of further permanent rate recovery plans, actions relating to proposed securitization, satisfaction of requirements to utilize grants, and the ultimate impact of the termination of the proposed sale of an interest in the Kemper IGCC to SMEPA;

7

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

(continued)

• the ability to successfully operate the electric utilities' generating, transmission, and distribution facilities and the successful performance of necessary corporate functions;

• the inherent risks involved in operating and constructing nuclear generating facilities, including environmental, health, regulatory, natural disaster, terrorism, and financial risks;

• the performance of projects undertaken by the non-utility businesses and the success of efforts to invest in and develop new opportunities;

• internal restructuring or other restructuring options that may be pursued;

• potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or beneficial to Southern Company or its subsidiaries;

• the expected timing, likelihood, and benefits of completion of the Merger, including the failure to receive, on a timely basis or otherwise, the required approvals by government or regulatory agencies (including the terms of such approvals), the possibility that long-term financing for the Merger may not be put in place prior to the closing, the risk that a condition to closing of the Merger or funding of the Bridge Agreement may not be satisfied, the possibility that the anticipated benefits from the Merger cannot be fully realized or may take longer to realize than expected, the possibility that costs related to the integration of Southern Company and AGL Resources will be greater than expected, the credit ratings of the combined company or its subsidiaries may be different from what the parties expect, the ability to retain and hire key personnel and maintain relationships with customers, suppliers, or other business partners, the diversion of management time on Merger-related issues, and the impact of legislative, regulatory, and competitive changes;

• the ability of counterparties of Southern Company and its subsidiaries to make payments as and when due and to perform as required;

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

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

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

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

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

• the ability of Southern Company's subsidiaries to obtain additional generating capacity (or sell excess generating capacity) at competitive prices;

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

• the direct or indirect effects on the Southern Company system's business resulting from incidents affecting the U.S. electric grid or operation of generating resources;

• the effect of accounting pronouncements issued periodically by standard-setting bodies; and

• other factors discussed elsewhere herein and in other reports (including the Form 10-K) filed by the registrants from time to time with the SEC.

The registrants expressly disclaim any obligation to update any forward-looking statements.

8

THE SOUTHERN COMPANY

AND SUBSIDIARY COMPANIES

9

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended March 31,
	2016			2015
	(in millions)
Operating Revenues:
Retail revenues	$	3,377		$	3,542
Wholesale revenues	396			467
Other electric revenues	181			163
Other revenues	11			11
Total operating revenues	3,965			4,183
Operating Expenses:
Fuel	911			1,212
Purchased power	165			144
Other operations and maintenance	1,106			1,122
Depreciation and amortization	541			487
Taxes other than income taxes	256			252
Estimated loss on Kemper IGCC	53			9
Total operating expenses	3,032			3,226
Operating Income	933			957
Other Income and (Expense):
Allowance for equity funds used during construction	53			63
Interest expense, net of amounts capitalized	(246		)	(213		)
Other income (expense), net	(21		)	(8		)
Total other income and (expense)	(214		)	(158		)
Earnings Before Income Taxes	719			799
Income taxes	222			274
Consolidated Net Income	497			525
Less:
Dividends on Preferred and Preference Stock of Subsidiaries	11			17
Net income attributable to noncontrolling interests	1			—
Consolidated Net Income Attributable to Southern Company	$	485		$	508
Common Stock Data:
Earnings per share (EPS) —
Basic EPS	$	0.53		$	0.56
Diluted EPS	$	0.53		$	0.56
Average number of shares of common stock outstanding (in millions)
Basic	916			910
Diluted	922			915
Cash dividends paid per share of common stock	$	0.5425		$	0.5250

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

10

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended March 31,
	2016			2015
	(in millions)
Consolidated Net Income	$	497		$	525
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(72) and $(11), respectively	(117		)	(18		)
Reclassification adjustment for amounts included in net income, net of tax of $1 and $1, respectively	2			1
Pension and other post retirement benefit plans:
Reclassification adjustment for amounts included in net income, net of tax of $1 and $1, respectively	1			2
Total other comprehensive income (loss)	(114		)	(15		)
Less:
Dividends on preferred and preference stock of subsidiaries	11			17
Comprehensive income attributable to noncontrolling interests	1			—
Consolidated Comprehensive Income Attributable to Southern Company	$	371		$	493

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

11

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Three Months Ended March 31,
	2016			2015
	(in millions)
Operating Activities:
Consolidated net income	$	497		$	525
Adjustments to reconcile consolidated net income to net cash provided from operating activities —
Depreciation and amortization, total	639			578
Deferred income taxes	(4		)	113
Allowance for equity funds used during construction	(53		)	(63		)
Stock based compensation expense	58			56
Estimated loss on Kemper IGCC	53			9
Other, net	(13		)	4
Changes in certain current assets and liabilities —
-Receivables	235			180
-Fossil fuel stock	31			76
-Materials and supplies	(14		)	4
-Other current assets	(90		)	(89		)
-Accounts payable	(72		)	(426		)
-Accrued taxes	(60		)	197
-Accrued compensation	(332		)	(381		)
-Retail fuel cost over recovery - short-term	25			49
-Mirror CWIP	—			40
-Other current liabilities	(35		)	41
Net cash provided from operating activities	865			913
Investing Activities:
Plant acquisitions	(114		)	(6		)
Property additions	(1,872		)	(1,091		)
Investment in restricted cash	(289		)	—
Distribution of restricted cash	292			—
Nuclear decommissioning trust fund purchases	(316		)	(290		)
Nuclear decommissioning trust fund sales	311			284
Cost of removal, net of salvage	(52		)	(36		)
Change in construction payables, net	(94		)	65
Prepaid long-term service agreement	(49		)	(37		)
Other investing activities	(14		)	4
Net cash used for investing activities	(2,197		)	(1,107		)
Financing Activities:
Increase in notes payable, net	294			597
Proceeds —
Long-term debt issuances	1,997			550
Common stock issuances	270			112
Short-term borrowings	—			280
Redemptions and repurchases —
Long-term debt	(888		)	(333		)
Common stock repurchased	—			(115		)
Short-term borrowings	(475		)	—
Distributions to noncontrolling interests	(4		)	—
Capital contributions from noncontrolling interests	131			—
Purchase of membership interests from noncontrolling interests	(129		)	—
Payment of common stock dividends	(497		)	(478		)
Other financing activities	(17		)	(17		)
Net cash provided from financing activities	682			596
Net Change in Cash and Cash Equivalents	(650		)	402
Cash and Cash Equivalents at Beginning of Period	1,404			710
Cash and Cash Equivalents at End of Period	$	754		$	1,112
Supplemental Cash Flow Information:
Cash paid (received) during the period for --
Interest (net of $30 and $32 capitalized for 2016 and 2015, respectively)	$	224		$	207
Income taxes, net	(141		)	(289		)
Noncash transactions — Accrued property additions at end of period	731			347

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

12

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

Assets	At March 31, 2016			At December 31, 2015
	(in millions)
Current Assets:
Cash and cash equivalents	$	754		$	1,404
Receivables —
Customer accounts receivable	988			1,058
Unbilled revenues	380			397
Under recovered regulatory clause revenues	43			63
Income taxes receivable, current	—			144
Other accounts and notes receivable	236			398
Accumulated provision for uncollectible accounts	(13		)	(13		)
Fossil fuel stock, at average cost	837			868
Materials and supplies, at average cost	1,085			1,061
Vacation pay	181			178
Prepaid expenses	486			495
Other regulatory assets, current	394			402
Other current assets	90			71
Total current assets	5,461			6,526
Property, Plant, and Equipment:
In service	76,553			75,118
Less accumulated depreciation	24,566			24,253
Plant in service, net of depreciation	51,987			50,865
Other utility plant, net	218			233
Nuclear fuel, at amortized cost	941			934
Construction work in progress	9,406			9,082
Total property, plant, and equipment	62,552			61,114
Other Property and Investments:
Nuclear decommissioning trusts, at fair value	1,540			1,512
Leveraged leases	761			755
Miscellaneous property and investments	488			485
Total other property and investments	2,789			2,752
Deferred Charges and Other Assets:
Deferred charges related to income taxes	1,572			1,560
Unamortized loss on reacquired debt	220			227
Other regulatory assets, deferred	4,957			4,989
Income taxes receivable, non-current	413			413
Other deferred charges and assets	771			737
Total deferred charges and other assets	7,933			7,926
Total Assets	$	78,735		$	78,318

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

13

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholders' Equity	At March 31, 2016			At December 31, 2015
	(in millions)
Current Liabilities:
Securities due within one year	$	2,392		$	2,674
Notes payable	1,195			1,376
Accounts payable	1,584			1,905
Customer deposits	406			404
Accrued taxes —
Accrued income taxes	14			19
Other accrued taxes	240			484
Accrued interest	255			249
Accrued vacation pay	228			228
Accrued compensation	212			549
Asset retirement obligations, current	237			217
Liabilities from risk management activities	319			156
Other regulatory liabilities, current	210			278
Other current liabilities	564			590
Total current liabilities	7,856			9,129
Long-term Debt	26,091			24,688
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	12,274			12,322
Deferred credits related to income taxes	185			187
Accumulated deferred investment tax credits	1,350			1,219
Employee benefit obligations	2,546			2,582
Asset retirement obligations, deferred	3,504			3,542
Unrecognized tax benefits	375			370
Other cost of removal obligations	1,151			1,162
Other regulatory liabilities, deferred	303			254
Other deferred credits and liabilities	754			720
Total deferred credits and other liabilities	22,442			22,358
Total Liabilities	56,389			56,175
Redeemable Preferred Stock of Subsidiaries	118			118
Redeemable Noncontrolling Interests	44			43
Stockholders' Equity:
Common Stockholders' Equity:
Common stock, par value $5 per share —
Authorized — 1.5 billion shares
Issued -- March 31, 2016: 922 million shares
-- December 31, 2015: 915 million shares
Treasury -- March 31, 2016: 3.4 million shares
-- December 31, 2015: 3.4 million shares
Par value	4,604			4,572
Paid-in capital	6,582			6,282
Treasury, at cost	(144		)	(142		)
Retained earnings	9,999			10,010
Accumulated other comprehensive loss	(244		)	(130		)
Total Common Stockholders' Equity	20,797			20,592
Preferred and Preference Stock of Subsidiaries	609			609
Noncontrolling Interests	778			781
Total Stockholders' Equity	22,184			21,982
Total Liabilities and Stockholders' Equity	$	78,735		$	78,318

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

14

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

FIRST QUARTER 2016 vs. FIRST QUARTER 2015

OVERVIEW

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

Proposed Merger with AGL Resources

On August 23, 2015, Southern Company entered into the Merger Agreement to acquire AGL Resources. Under the terms of the Merger Agreement, subject to the satisfaction or waiver (if permissible under applicable law) of specified conditions, Merger Sub will be merged with and into AGL Resources. AGL Resources will survive the Merger and become a wholly-owned, direct subsidiary of Southern Company.

Southern Company intends to fund the cash consideration for the Merger using a mix of debt and equity. Southern Company finances its capital needs on a portfolio basis and expects to issue a minimum of $8.0 billion in debt prior to closing the Merger and a minimum of $1.2 billion in equity during 2016. This capital is expected to provide funding for the Merger, the proposed acquisition of PowerSecure International, Inc. (PowerSecure), and Southern Power and other Southern Company system capital projects. Total capital raised in 2016 may increase due to cash needed at the closing of the Merger, settlement of hedges, and incremental investment opportunities, including additional Southern Power projects in excess of its current capital plans. In addition, Southern Company entered into the $8.1 billion Bridge Agreement on September 30, 2015 to provide financing for the Merger in the event long-term financing is not available.

Through May 5, 2016, the Maryland PSC, the Georgia PSC, the California Public Utilities Commission, and the Virginia State Corporation Commission have approved the Merger. On April 15, 2016, Southern Company, AGL Resources, and Northern Illinois Gas Company (collectively, the Joint Applicants) and the Retail Energy Supply Association filed a settlement agreement with the Illinois Commerce Commission. On April 28, 2016, the Joint Applicants, the Illinois Attorney General's Office, and the Citizens Utility Board filed a settlement agreement with the Illinois Commerce Commission. Collectively, these agreements resolve all remaining contested issues for Illinois Commerce Commission approval of the Merger. On May 5, 2016, Southern Company, AGL Resources, Merger Sub, Pivotal Utility Holdings, Inc. d/b/a Elizabethtown Gas, the Division of Rate Counsel, the Staff of the New Jersey Board of Public Utilities, and New Jersey Large Energy Users Coalition entered into a comprehensive settlement agreement relating to the New Jersey Board of Public Utilities review of the Merger. Additionally, the Federal Communications Commission (FCC) has approved the transfer of control over the FCC licenses of certain AGL Resources subsidiaries. Consummation of the Merger remains subject to the satisfaction or waiver of certain closing conditions, including, among others, (i) the approval of the Illinois Commerce Commission and the New Jersey Board of Public Utilities and other approvals required under applicable state laws, (ii) the absence of a judgment, order, decision, injunction, ruling, or other finding or agency requirement of a governmental entity prohibiting the consummation of the Merger, and (iii) other customary closing conditions, including (a) subject to certain materiality qualifiers, the accuracy of each party's representations and warranties and (b) each party's performance in all material respects of its obligations under the Merger Agreement.

15

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Prior to the Merger, Southern Company and AGL Resources will continue to operate as separate companies. Accordingly, except for specific references to the pending Merger, the descriptions of strategy and outlook and the risks and challenges Southern Company faces, and the discussion and analysis of results of operations and financial condition set forth herein relate solely to Southern Company. See Note (I) to the Condensed Financial Statements under "Southern Company – Proposed Merger with AGL Resources" herein for additional information regarding the Merger.

During the first quarter 2016, Southern Company recorded in its statements of income external transaction costs for financing, legal, and consulting services associated with the proposed Merger of approximately $20 million, of which $6 million is included in operating expenses and $14 million is included in other income and (expense).

The ultimate outcome of these matters cannot be determined at this time. See RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – OVERVIEW – "Proposed Merger with AGL Resources" of Southern Company in Item 7 of the Form 10-K for additional information related to the proposed Merger and the various risks related thereto.

Construction Program

Construction continues on Plant Vogtle Units 3 and 4 (45.7% ownership interest by Georgia Power in the two units, each with approximately 1,100 MWs) and Mississippi Power's 582-MW Kemper IGCC. See RESULTS OF OPERATIONS – "Estimated Loss on Kemper IGCC," FUTURE EARNINGS POTENTIAL – "Construction Program," and Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" and "Integrated Coal Gasification Combined Cycle" herein for additional information. For information about Southern Power's acquisitions and construction of renewable energy facilities, see Note (I) to the Condensed Financial Statements under "Southern Power" herein.

Key Performance Indicators

Southern Company continues to focus on several key performance indicators. These indicators include customer satisfaction, plant availability, system reliability, execution of major construction projects, and earnings per share. For additional information on these indicators, see MANAGEMENT'S DISCUSSION AND ANALYSIS – OVERVIEW – "Key Performance Indicators" of Southern Company in Item 7 of the Form 10-K.

RESULTS OF OPERATIONS

Net Income

First Quarter 2016 vs. First Quarter 2015
(change in millions)	(% change)
$(23)	(4.5)

Consolidated net income attributable to Southern Company was $485 million ($0.53 per share) for the first quarter 2016 compared to $508 million ($0.56 per share) for the first quarter 2015. The decrease was primarily the result of lower retail revenues due to milder weather in the first quarter 2016 as compared to the corresponding period in 2015, higher depreciation and amortization, higher charges related to revisions of the estimated costs expected to be incurred on Mississippi Power's construction of the Kemper IGCC, and lower wholesale capacity revenues. The decreases were partially offset by increases in revenues due to increases in non-fuel retail rates and sales growth and a decrease in income taxes primarily from income tax benefits at Southern Power.

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.

16

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Retail Revenues

First Quarter 2016 vs. First Quarter 2015
(change in millions)	(% change)
$(165)	(4.7)

In the first quarter 2016, retail revenues were $3.4 billion compared to $3.5 billion for the corresponding period in 2015.

Details of the changes in retail revenues were as follows:

	First Quarter 2016
	(in millions)			(% change)
Retail – prior year	$	3,542
Estimated change resulting from –
Rates and pricing	110			3.1
Sales growth	22			0.6
Weather	(85		)	(2.4	)
Fuel and other cost recovery	(212		)	(6.0	)
Retail – current year	$	3,377		(4.7	)%

Revenues associated with changes in rates and pricing increased in the first quarter 2016 when compared to the corresponding period in 2015 primarily due to increased revenues at Alabama Power under Rate CNP Compliance and at Georgia Power related to increases in base tariffs under the 2013 ARP and the NCCR tariff, all effective January 1, 2016. The increase in rates and pricing was also due to the implementation of rates for certain Kemper IGCC in-service assets at Mississippi Power.

See Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Alabama Power," "Retail Regulatory Matters – Georgia Power – Rate Plans" and " – Nuclear Construction," and "Integrated Coal Gasification Combined – Cycle – Rate Recovery of Kemper IGCC Costs" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for additional information.

Revenues attributable to changes in sales increased in the first quarter 2016 when compared to the corresponding period in 2015. Weather-adjusted residential KWH sales increased 1.4% in the first quarter 2016 due to customer growth and increased customer usage. Weather-adjusted commercial KWH sales increased 0.8% in the first quarter 2016 primarily due to customer growth. Industrial KWH sales decreased 1.0% in the first quarter 2016 primarily due to decreased sales in the chemicals, primary metals, non-manufacturing, and pipeline sectors, partially offset by increased sales in the paper and stone, clay, and glass sectors. A strong dollar, low oil prices, and weak global growth conditions have constrained growth in the industrial sector.

In the first quarter 2015, Mississippi Power updated the methodology to estimate the unbilled revenue allocation among customer classes. This change did not have a significant impact on net income. The KWH sales variances discussed above reflect an adjustment to the estimated allocation of Mississippi Power's unbilled first quarter 2015 KWH sales among customer classes that is consistent with the actual allocation in 2016. Without this adjustment, first quarter 2016 weather-adjusted residential sales increased 1.6%, weather-adjusted commercial sales increased 1.1%, and industrial KWH sales decreased 0.8% as compared to the corresponding period in 2015.

Fuel and other cost recovery revenues decreased $212 million in the first quarter 2016, respectively, when compared to the corresponding period in 2015 primarily due to a decrease in fuel prices.

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

17

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

Wholesale Revenues

First Quarter 2016 vs. First Quarter 2015
(change in millions)	(% change)
$(71)	(15.2)

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

In the first quarter 2016, wholesale revenues were $396 million compared to $467 million for the corresponding period in 2015 related to a $43 million decrease in capacity revenues and a $28 million decrease in energy revenues. The decrease in capacity revenues was primarily due to a PPA remarketing from non-affiliate to affiliate at Southern Power, unit retirements at Georgia Power, milder weather and decreased usage at Mississippi Power, and the expiration of a Plant Scherer Unit 3 power sales agreement at Gulf Power. The decrease in energy revenues was primarily related to lower fuel costs.

See FUTURE EARNINGS POTENTIAL – "Other Matters" herein for additional information regarding the expiration of long-term sales agreements at Gulf Power for Plant Scherer Unit 3, which will impact future wholesale earnings.

Other Electric Revenues

First Quarter 2016 vs. First Quarter 2015
(change in millions)	(% change)
$18	11.0

In the first quarter 2016, other electric revenues were $181 million compared to $163 million for the corresponding period in 2015. The increase was primarily due to an adjustment for customer temporary facilities service revenues at Georgia Power.

Fuel and Purchased Power Expenses

	First Quarter 2016 vs. First Quarter 2015
	(change in millions)			(% change)
Fuel	$	(301	)	(24.8)
Purchased power	21			14.6
Total fuel and purchased power expenses	$	(280	)

In the first quarter 2016, total fuel and purchased power expenses were $1.1 billion compared to $1.4 billion for the corresponding period in 2015. The decrease was primarily the result of a $223 million decrease in the average cost

18

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

of fuel and purchased power primarily due to lower natural gas and coal prices and a $145 million decrease in the volume of KWHs generated, partially offset by an $88 million increase in the volume of KWHs purchased.

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

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

	First Quarter 2016	First Quarter 2015
Total generation (billions of KWHs)	44	46
Total purchased power (billions of KWHs)	4	3
Sources of generation (percent) —
Coal	27	33
Nuclear	17	16
Gas	47	47
Hydro	7	3
Other Renewables	2	1
Cost of fuel, generated (cents per net KWH) —
Coal	3.24	3.70
Nuclear	0.82	0.67
Gas	2.16	2.71
Average cost of fuel, generated (cents per net KWH)	2.23	2.71
Average cost of purchased power (cents per net KWH)(*)	5.27	7.18

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

Fuel

In the first quarter 2016, fuel expense was $911 million compared to $1.2 billion for the corresponding period in 2015. The decrease was primarily due to a 21.9% decrease in the volume of KWHs generated by coal, a 20.3% decrease in the average cost of natural gas per KWH generated, a 12.4% decrease in the average cost of coal per KWH generated, and an 83.1% increase in the volume of KWHs generated by hydro facilities resulting from more rainfall.

Purchased Power

In the first quarter 2016, purchased power expense was $165 million compared to $144 million for the corresponding period in 2015. The increase was primarily due to a 50.8% increase in the volume of KWHs purchased, partially offset by a 26.6% decrease in the average cost per KWH purchased primarily as a result of lower natural gas and coal 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.

19

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Other Operations and Maintenance Expenses

First Quarter 2016 vs. First Quarter 2015
(change in millions)	(% change)
$(16)	(1.4)

In the first quarter 2016, other operations and maintenance expenses were $1.11 billion compared to $1.12 billion for the corresponding period in 2015. The decrease was primarily due to a decrease in scheduled outage and maintenance costs at generation facilities and a decrease in employee compensation and benefits including pension costs.

Depreciation and Amortization

First Quarter 2016 vs. First Quarter 2015
(change in millions)	(% change)
$54	11.1

In the first quarter 2016, depreciation and amortization was $541 million compared to $487 million for the corresponding period in 2015. The increase was primarily due to a $43 million increase related to additional plant in service at the traditional operating companies and Southern Power. Also contributing to the increase, Gulf Power recorded $14 million less of a reduction in depreciation in the first three months of 2016 compared to the corresponding period in 2015, as authorized by the Florida PSC in a settlement agreement.

See Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Gulf Power – 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.

Estimated Loss on Kemper IGCC

First Quarter 2016 vs. First Quarter 2015
(change in millions)	(% change)
$44	N/M

N/M – Not meaningful

In the first quarter 2016 and 2015, estimated probable losses on the Kemper IGCC of $53 million and $9 million, respectively, were recorded at Southern Company. These losses reflect revisions of estimated costs expected to be incurred on Mississippi Power's construction of the Kemper IGCC in excess of the $2.88 billion cost cap established by the Mississippi PSC, net of $245 million of grants awarded to the project by the DOE under the Clean Coal Power Initiative Round 2 (Initial 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 – Integrated Coal Gasification Combined Cycle" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.

20

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Allowance for Equity Funds Used During Construction

First Quarter 2016 vs. First Quarter 2015
(change in millions)	(% change)
$(10)	(15.9)

In the first quarter 2016, AFUDC equity was $53 million compared to $63 million for the corresponding period in 2015. The decrease was primarily due to environmental and generation projects placed in service at Alabama Power and Gulf Power.

Interest Expense, Net of Amounts Capitalized

First Quarter 2016 vs. First Quarter 2015
(change in millions)	(% change)
$33	15.5

In the first quarter 2016, interest expense, net of amounts capitalized was $246 million compared to $213 million in the corresponding period in 2015. The increase was primarily due to an increase in outstanding long-term debt, partially offset by a decrease related to interest on deposits resulting from the termination of an asset purchase agreement between Mississippi Power and SMEPA in May 2015.

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

Other Income (Expense), Net

First Quarter 2016 vs. First Quarter 2015
(change in millions)	(% change)
$(13)	N/M

N/M – Not meaningful

In the first quarter 2016, other income (expense), net was $(21) million compared to $(8) million for the corresponding period in 2015. The change was primarily due to Bridge Agreement-related expenses associated with the proposed Merger.

See Note (I) to the Condensed Financial Statements under "Southern Company – Proposed Merger with AGL Resources" herein for additional information.

Income Taxes

First Quarter 2016 vs. First Quarter 2015
(change in millions)	(% change)
$(52)	(19.0)

In the first quarter 2016, income taxes were $222 million compared to $274 million for the corresponding period in 2015. The decrease was primarily due to increased federal income tax benefits from ITCs and PTCs at Southern Power and an increase in tax benefits related to estimated probable losses on Mississippi Power's construction of the Kemper IGCC.

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 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

21

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

factors include the traditional operating companies' 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 the Kemper IGCC and Plant Vogtle Units 3 and 4 as well as other ongoing construction projects. Other major factors include the profitability of Southern Power's competitive wholesale business and successful additional investments in renewable and other energy projects. Future earnings for the electricity business in the near term will depend, in part, upon maintaining and growing sales which are subject to a number of factors. These factors include weather, competition, new energy contracts with other utilities and other wholesale customers, energy conservation practiced by customers, the use of alternative energy sources by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in the service territory. In addition, the level of future earnings for the wholesale business also depends on numerous factors including regulatory matters, creditworthiness of customers, total generating capacity available and related costs, future acquisitions and construction of generating facilities, the impact of tax credits from renewable energy projects, and the successful remarketing of capacity as current contracts expire. Demand for electricity is primarily driven by economic growth. The pace of economic growth and electricity demand may be affected by changes in regional and global economic conditions, which may impact future earnings.

As part of its ongoing effort to adapt to changing market conditions, Southern Company continues to evaluate and consider a wide array of potential business strategies. These strategies may include business combinations, partnerships, and acquisitions involving other utility or non-utility businesses or properties, disposition of certain assets, internal restructuring, or some combination thereof. Furthermore, Southern Company may engage in new business ventures that arise from competitive and regulatory changes in the utility industry. Pursuit of any of the above strategies, or any combination thereof, may significantly affect the business operations, risks, and financial condition of Southern Company. In addition, the proposed Merger will result in a combined company that is subject to various risks that do not currently impact Southern Company.

For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Southern Company in Item 7 of the Form 10-K.

Environmental Matters

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

Environmental Statutes and Regulations

Air Quality

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Air Quality" of Southern Company in Item 7 of the Form 10-K for additional information regarding the EPA's final MATS rule and regional haze regulations.

On April 25, 2016, in response to a June 2015 U.S. Supreme Court opinion, the EPA published its supplemental finding regarding consideration of costs in support of the MATS rule. This finding does not impact MATS rule compliance requirements, costs, or deadlines, and all units within the Southern Company system that are subject to

22

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

the MATS rule have completed the measures necessary to achieve compliance with the MATS rule by the applicable deadlines.

Also on April 25, 2016, the EPA issued proposed revisions to the regional haze regulations. The ultimate impact of the proposed revisions will depend on their ultimate adoption, implementation, and any legal challenges and cannot be determined at this time.

Retail Regulatory Matters

Retail Fuel Cost Recovery

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Retail Fuel Cost Recovery" of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Alabama Power – Rate ECR" and "Retail Regulatory Matters – Georgia Power – Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information regarding 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 and make appropriate filings with their state PSCs to adjust fuel cost recovery rates as necessary.

On April 14, 2016, Georgia Power filed a request with the Georgia PSC to decrease fuel rates by 15% effective June 1, 2016, which is expected to reduce annual billings by approximately $313 million. Georgia Power is currently scheduled to file its next fuel case by February 28, 2017. The ultimate outcome of this matter cannot be determined at this time.

Renewables

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Renewables" of Southern Company in Item 7 of the Form 10-K for additional information regarding the Southern Company system's renewables activity.

As part of the Georgia Power Advanced Solar Initiative, four PPAs totaling 149 MWs of Georgia Power's solar contracted capacity from Southern Power began in the first quarter 2016.

In November 2015, the Mississippi PSC issued orders approving three solar facilities for a combined total of approximately 105 MWs. Mississippi Power will purchase all of the energy produced by the solar facilities for the 25-year term under each of the three PPAs, two of which were finalized as of December 31, 2015 and one of which was finalized as of March 2, 2016. The projects are expected to be in service by the end of 2016 and the resulting energy purchases are expected to be recovered through Mississippi Power's fuel cost recovery mechanism.

The Florida PSC issued a final approval order on Gulf Power's Community Solar Pilot Program on April 15, 2016. The program will offer all Gulf Power customers an opportunity to voluntarily contribute to the construction and operation of a solar photovoltaic facility with electric generating capacity of up to 1 MW through annual subscriptions. The energy generated from the solar facility is expected to provide power to all of Gulf Power's customers.

Alabama Power

Alabama Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Alabama PSC. Alabama Power currently recovers its costs from the regulated retail business primarily through its Rate RSE, Rate CNP Compliance, rate energy cost recovery, and natural disaster reserve rate. In addition, the Alabama PSC issues accounting orders to address current events impacting Alabama Power. See Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Alabama Power" in

23

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Item 8 of the Form 10-K for additional information regarding Alabama Power's rate mechanisms and accounting orders. The recovery balance of each regulatory clause for Alabama Power is reported in Note (B) to the Condensed Financial Statements herein.

Georgia Power

Georgia Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Georgia PSC. Georgia Power currently recovers its costs from the regulated retail business through the 2013 ARP, which includes traditional base tariff rates, Demand-Side Management tariffs, Environmental Compliance Cost Recovery tariffs, and Municipal Franchise Fee tariffs. In addition, financing costs related to the construction of Plant Vogtle Units 3 and 4 are being collected through the NCCR tariff and fuel costs are collected through separate fuel cost recovery tariffs. See Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Fuel Cost Recovery" herein and 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 regarding Georgia Power's fuel cost recovery and the NCCR tariff, respectively.

Pursuant to the terms and conditions of a settlement agreement related to Southern Company's proposed acquisition of AGL Resources approved by the Georgia PSC on April 14, 2016, Georgia Power's 2013 ARP will continue in effect until December 31, 2019, and Georgia Power will be required to file its next base rate case by July 1, 2019. Furthermore, through December 31, 2019, Georgia Power and Atlanta Gas Light Company (collectively, Utilities) will retain the merger savings, net of transition costs, as defined in the settlement agreement; through December 31, 2022, net merger savings will be shared on a 60/40 basis between customers and the Utilities; thereafter, all merger savings will be retained by customers. See Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Georgia Power" in Item 8 of the Form 10-K for additional information regarding the 2013 ARP and Note (I) to the Condensed Financial Statements under "Southern Company – Proposed Merger with AGL Resources" herein for additional information regarding the Merger.

Construction Program

Overview

The subsidiary companies of Southern Company are engaged in continuous construction programs to accommodate existing and estimated future loads on their respective systems. The Southern Company system intends to continue its strategy of developing and constructing new generating facilities, as well as adding or changing fuel sources for certain existing units, adding environmental control equipment, and expanding the transmission and distribution systems. For the traditional operating companies, major generation construction projects are subject to state PSC approval in order to be included in retail rates. While Southern Power generally constructs and acquires generation assets covered by long-term PPAs, any uncontracted capacity could negatively affect future earnings.

The two largest construction projects currently underway in the Southern Company system are Plant Vogtle Units 3 and 4 (45.7% ownership interest by Georgia Power in the two units, each with approximately 1,100 MWs) and Mississippi Power's 582-MW Kemper IGCC. See Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" and "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" and "Integrated Coal Gasification Combined Cycle" herein for additional information. For additional information about costs relating to Southern Power's acquisitions that involve construction of renewable energy facilities, see Note 12 to the financial statements of Southern Company under "Southern Power – Construction Projects" in Item 8 of the Form 10-K and Note (I) to the Condensed Financial Statements under "Southern Power – Construction Projects" herein.

Also see FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein for additional information regarding Southern Company's capital requirements for its subsidiaries' construction programs.

24

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Integrated Coal Gasification Combined Cycle

Mississippi Power's current cost estimate for the Kemper IGCC in total is approximately $6.58 billion, which includes approximately $5.35 billion of costs subject to the construction cost cap and is net of $137 million in additional DOE grants Mississippi Power received for the Kemper IGCC on April 8, 2016 (Additional DOE Grants), which are expected to be used to reduce future rate impacts for customers. Mississippi Power does not intend to seek any rate recovery for any related costs that exceed the $2.88 billion cost cap, net of the Initial DOE Grants and excluding the Cost Cap Exceptions. In the aggregate, Southern Company has incurred charges of $2.47 billion ($1.52 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through March 31, 2016. Mississippi Power's current cost estimate includes costs through September 30, 2016. 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 Initial DOE Grants and excluding the Cost Cap Exceptions, will be reflected in Southern Company's statements of income and these changes could be material.

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

Civil Lawsuit

On April 26, 2016, a complaint against Mississippi Power was filed in Harrison County Circuit Court by Biloxi Freezing & Processing Inc., Gulfside Casino Partnership, and John Carlton Dean. The plaintiffs allege that Mississippi Power violated the Mississippi Unfair Trade Practices Act and concealed, falsely represented, and failed to fully disclose important facts concerning the cost and schedule of the Kemper IGCC and that Mississippi Power's alleged breaches interfered with and destroyed economically advantageous relationships between the plaintiffs and their current and prospective business associates. The plaintiffs seek unspecified actual damages and punitive damages as well as attorney's fees, costs, and interest. The plaintiffs also seek an injunction to prevent any Kemper IGCC costs from being charged to customers through electric rates. Mississippi Power believes this legal challenge has no merit; however, an adverse outcome in this proceeding could have an impact on Southern Company's results of operations, financial condition, and liquidity. Mississippi Power will vigorously defend the matter, and the final outcome of this matter cannot be determined at this time.

Other Matters

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

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

The SEC is conducting a formal investigation of Southern Company and Mississippi Power concerning the estimated costs and expected in-service date of the Kemper IGCC. Southern Company and Mississippi Power believe the investigation is focused primarily on periods subsequent to 2010 and on accounting matters, disclosure controls and procedures, and internal controls over financial reporting associated with the Kemper IGCC. See ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" herein for additional

25

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

information on the Kemper IGCC estimated construction costs and expected in-service date. Southern Company and Mississippi Power are cooperating fully with the SEC. The ultimate outcome of this matter cannot be determined at this time; however, it is not expected to have a material impact on the financial statements of Southern Company.

Through 2015, capacity revenues from long-term non-affiliate sales out of Gulf Power's ownership of Plant Scherer Unit 3 (205 MWs) represented the majority of Gulf Power's wholesale earnings. The capacity revenues associated with these contracts covering 100% of Gulf Power's ownership represented 82% of Gulf Power's wholesale capacity revenues in 2015. Due to the expiration of a wholesale contract at the end of 2015 and another wholesale contract at the end of May 2016, Gulf Power's remaining contracted sales from the unit from June 2016 through 2019 will cover approximately 24% of the unit. The expiration of the contract in 2015 and the scheduled future expiration of the remaining contracts are not expected to have a material impact on Southern Company's earnings. The alternatives Gulf Power is actively evaluating include, without limitation, rededication of the asset to serve retail customers for whom it was originally planned and built, replacement long-term wholesale contracts or other sales into the wholesale market, or an asset sale. On May 5, 2016, Gulf Power delivered a letter to the Florida PSC requesting recognition of Gulf Power's ownership in Plant Scherer Unit 3 as being in service to retail customers when and as the contracts expire. The ultimate outcome of this matter cannot be determined at this time.

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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

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

During 2016, Mississippi Power further revised its cost estimate to complete construction and start-up of the Kemper IGCC to an amount that exceeds the $2.88 billion cost cap, net of the Initial DOE Grants and excluding the Cost Cap Exceptions. Mississippi Power does not intend to seek any rate recovery for any costs related to the construction of the Kemper IGCC that exceed the $2.88 billion cost cap, net of the Initial 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 $53 million ($33 million after tax) in the first quarter 2016, $183 million ($113 million after tax) in the fourth quarter 2015, $150 million ($93 million after tax) in the third quarter 2015, $23 million ($14 million after tax) in the second quarter 2015, $9 million ($6 million after tax) in the first quarter 2015, $70 million ($43 million after tax) in the fourth quarter 2014, $418 million ($258 million after tax) in the third quarter 2014, $380 million ($235 million after tax) in the first quarter 2014, $40 million ($25 million after tax) in the fourth quarter 2013, $150 million ($93 million after tax) in the third quarter 2013, $450 million ($278 million after tax) in the second quarter 2013, and $540 million ($333 million after tax) in the first quarter 2013. In the aggregate, Southern Company has incurred charges of $2.47 billion ($1.52 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through March 31, 2016.

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 Initial DOE Grants and excluding the Cost Cap Exceptions, will be reflected in Southern Company's statements of income and these changes could be material.

26

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 operating or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities for this first-of-a-kind technology (including, but not limited to, major equipment failure and system integration), and/or operational performance (including, but not limited to, additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC).

Mississippi Power's revised cost estimate includes costs through September 30, 2016. Any extension of the in-service date beyond September 30, 2016 is currently estimated to result in additional base costs of approximately $25 million to $35 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. However, additional costs may be required for remediation of any further equipment and/or design issues identified. Any extension of the in-service date with respect to the Kemper IGCC beyond September 30, 2016 would also increase costs for the Cost Cap Exceptions, which are not subject to the $2.88 billion cost cap established by the Mississippi PSC. These costs include AFUDC, which is currently estimated to total approximately $14 million per month, as well as carrying costs and operating expenses on Kemper IGCC assets placed in service and consulting and legal fees of approximately $2 million per month.

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

Recently Issued Accounting Standards

On February 25, 2016, the FASB issued ASU No. 2016-02, Leases(Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchangedand there is no change to the accounting for existing leveraged leases.ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. Southern Company is currently evaluating the new standard and has not yet determined its ultimate impact; however, adoption of ASU 2016-02 is expected to have a significant impact on Southern Company's balance sheet.

On March 30, 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation(Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions. Most significantly, entities are required to recognize all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation as income tax expense or benefit in the income statement. Southern Company currently recognizes any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation in additional paid-in capital. ASU 2016-09 is effective for fiscal years beginning after December 15, 2016, with early adoption permitted. Southern Company is currently evaluating the new standard and has not yet determined its ultimate impact.

27

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

FINANCIAL CONDITION AND LIQUIDITY

Overview

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Southern Company in Item 7 of the Form 10-K for additional information. Southern Company's financial condition remained stable at March 31, 2016. Through March 31, 2016, Southern Company has incurred non-recoverable cash expenditures of $2.11 billion and is expected to incur approximately $0.36 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 bank credit agreements to meet future capital and liquidity needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.

Net cash provided from operating activities totaled $0.9 billion for the first three months of 2016 and the corresponding period in 2015. Net cash used for investing activities totaled $2.2 billion for the first three months of 2016 primarily due to gross property additions for construction of generation, transmission, and distribution facilities and installation of equipment to comply with environmental standards. Net cash provided from financing activities totaled $0.7 billion for the first three months of 2016 primarily due to issuances of long-term debt, partially offset by redemptions of short-term and long-term debt and common stock dividend payments. Fluctuations in cash flow from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes for the first three months of 2016 include an increase of $1.4 billion in total property, plant, and equipment to comply with environmental standards and construction of generation, transmission, and distribution facilities; a $0.7 billion decrease in cash and cash equivalents due to the funding of acquisitions and construction of renewable energy projects; a $1.1 billion increase in short-term and long-term debt to fund the subsidiaries' continuous construction programs and for other general corporate purposes; a $0.3 billion decrease in accounts payable due to the timing of vendor payments; and a $0.3 billion decrease in accrued compensation due to the timing of payments.

At the end of the first quarter 2016, the market price of Southern Company's common stock was $51.73 per share (based on the closing price as reported on the New York Stock Exchange) and the book value was $22.65 per share, representing a market-to-book ratio of 228%, compared to $46.79, $22.59, and 207%, respectively, at the end of 2015. Southern Company's common stock dividend for the first quarter 2016 was $0.5425 per share compared to $0.5250 per share in the first quarter 2015.

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 $2.5 billion will be required through March 31, 2017 to fund maturities and announced redemptions of long-term debt. See "Sources of Capital" herein for additional information.

In addition to the cash consideration for the Merger to be paid by Southern Company at the effective time of the Merger, Southern Company will also assume AGL Resources' outstanding indebtedness (approximately $4.3 billion at March 31, 2016). See OVERVIEW herein for additional information regarding the Merger as well as Note (I) to the Condensed Financial Statements herein.

The Southern Company system's construction program is currently estimated to total $7.3 billion for 2016, $5.2 billion for 2017, and $5.5 billion for 2018. These amounts include expenditures of approximately $0.7 billion

28

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

related to the construction and start-up of the Kemper IGCC in 2016; $0.6 billion, $0.7 billion, and $0.4 billion to continue construction on Plant Vogtle Units 3 and 4 in 2016, 2017, and 2018, respectively; and $2.2 billion, $0.9 billion, and $1.4 billion for Southern Power's acquisitions and/or construction of new generating facilities in 2016, 2017, and 2018, respectively.

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 12 to the financial statements of Southern Company under "Southern Power" in Item 8 of the Form 10-K and Note (I) to the Condensed Financial Statements under "Southern Power" herein for additional information regarding Southern Power's plant acquisitions. See Note 3 to the financial statements of Southern Company under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" and "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" and "Integrated Coal Gasification Combined Cycle" herein for information regarding additional factors that may impact construction expenditures.

Sources of Capital

Southern Company intends to meet its future capital needs through operating cash flows, short-term debt, term loans, and external security issuances. Equity capital can be provided from any combination of Southern Company's stock plans, private placements, or public offerings. The amount and timing of additional equity capital and debt issuances in 2016, 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, external security issuances, term loans, short-term borrowings, and equity contributions or loans from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Southern Company in Item 7 of the Form 10-K for additional information.

In addition, Georgia Power may make borrowings through a loan guarantee agreement (Loan Guarantee Agreement) between Georgia Power and the DOE, the proceeds of which may be used to reimburse Georgia Power for Eligible Project Costs incurred in connection with its construction of Plant Vogtle Units 3 and 4. Under the Loan Guarantee Agreement, the DOE agreed to guarantee borrowings of up to $3.46 billion (not to exceed 70% of Eligible Project Costs) to be made by Georgia Power under a multi-advance credit facility (FFB Credit Facility) among Georgia Power, the DOE, and the FFB. See Note 6 to the financial statements of Southern Company under "DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K for additional information regarding the Loan Guarantee Agreement and Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" herein for additional information regarding Plant Vogtle Units 3 and 4.

Eligible Project Costs incurred through March 31, 2016 would allow for borrowings of up to $2.5 billion under the FFB Credit Facility, of which Georgia Power has borrowed $2.2 billion.

Mississippi Power received $245 million of Initial DOE Grants in prior years that were used for the construction of the Kemper IGCC. An additional $25 million of grants from the DOE is expected to be received for commercial operation of the Kemper IGCC. On April 8, 2016, Mississippi Power received approximately $137 million in

29

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Additional DOE Grants for the Kemper IGCC, which are expected to be used to reduce future rate impacts for customers. In addition, see Note 3 to the financial statements of Southern Company under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K for information regarding legislation related to the securitization of certain costs of the Kemper IGCC.

As of March 31, 2016, Southern Company's current liabilities exceeded current assets by $2.4 billion, primarily due to long-term debt that is due within one year, including approximately $0.9 billion at the parent company, $0.2 billion at Alabama Power, $0.5 billion at Georgia Power, $0.1 billion at Gulf Power, $0.3 billion at Mississippi Power, and $0.4 billion at Southern Power. To meet short-term cash needs and contingencies, Southern Company has substantial cash flow from operating activities and access to capital markets and financial institutions. Southern Company, the traditional operating companies, and Southern Power intend to utilize operating cash flows, as well as commercial paper, lines of credit, bank notes, and securities issuances, as market conditions permit, as well as, under certain circumstances for the traditional operating companies and Southern Power, equity contributions and/or loans from Southern Company to meet their short-term capital needs. In addition, for the remainder of 2016, Georgia Power expects to utilize borrowings through the FFB Credit Facility as an additional source of long-term borrowed funds.

At March 31, 2016, Southern Company and its subsidiaries had approximately $0.8 billion of cash and cash equivalents. Committed credit arrangements with banks at March 31, 2016 were as follows:

	Expires												Executable Term Loans				Due Within One Year
Company	2016		2017		2018		2020		Total		Unused		One Year		Two Years		Term Out		No Term Out
									(in millions)				(in millions)				(in millions)
Southern Company (a)	$	—	$	—	$	1,000	$	1,250	$	2,250	$	2,250	$	—	$	—	$	—	$	—
Alabama Power	40		—		500		800		1,340		1,340		—		—		—		40
Georgia Power	—		—		—		1,750		1,750		1,732		—		—		—		—
Gulf Power	75		40		165		—		280		280		45		—		45		40
Mississippi Power	205		—		—		—		205		180		30		15		45		160
Southern Power Company (b)	—		—		—		600		600		560		—		—		—		—
Other	70		—		—		—		70		70		20		—		20		50
Total	$	390	$	40	$	1,665	$	4,400	$	6,495	$	6,412	$	95	$	15	$	110	$	290

(a) Excludes the $8.1 billion Bridge Agreement entered into in September 2015 that will be funded only to the extent necessary to provide financing for the Merger as discussed herein.

(b) Excludes credit agreements (Project Credit Facilities) assumed with the acquisition of certain solar facilities, which are non-recourse to Southern Power Company, the proceeds of which are being used to finance project costs related to such solar facilities currently under construction. See Note (I) to the Condensed Financial Statements under "Southern Power" herein for additional information.

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.

Most of these bank credit arrangements, as well as the term loan arrangements of Southern Company, Alabama Power, Mississippi Power, and Southern Power, contain covenants that limit debt levels and contain cross acceleration or 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. Such cross acceleration provisions to other indebtedness would trigger an event of default if the applicable borrower defaulted on indebtedness, the payment of which was then accelerated. Southern Company, the traditional operating companies, and Southern Power Company are currently in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowings.

30

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Subject to applicable market conditions, Southern Company and its subsidiaries expect to renew or replace their bank credit arrangements as needed, prior to expiration. In connection therewith, Southern Company and its subsidiaries may extend the maturity dates and/or increase or decrease the lending commitments thereunder.

A portion of the unused credit with banks is allocated to provide liquidity support to the traditional operating companies' pollution control revenue bonds and commercial paper programs. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of March 31, 2016 was approximately $1.8 billion. In addition, at March 31, 2016, the traditional operating companies had approximately $269 million of fixed rate pollution control revenue bonds outstanding that were required to be reoffered within the next 12 months.

Southern Company intends to fund the cash consideration for the Merger using a mix of debt and equity. Southern Company finances its capital needs on a portfolio basis and expects to issue a minimum of $8.0 billion in debt prior to closing the Merger and a minimum of $1.2 billion in equity during 2016. This capital is expected to provide funding for the Merger, the proposed acquisition of PowerSecure, and Southern Power and other Southern Company system capital projects. Total capital raised in 2016 may increase due to cash needed at the closing of the Merger, settlement of hedges, and incremental investment opportunities, including additional Southern Power projects in excess of its current capital plans. Southern Company expects to issue the debt to fund the cash consideration for the Merger in several tranches including long-dated maturities. The amount of debt issued at each maturity will depend on prevailing market conditions at the time of the offering and other factors. In addition, Southern Company entered into the $8.1 billion Bridge Agreement on September 30, 2015 to provide financing for the Merger in the event long-term financing is not available. 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.

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, excluding the Bridge Agreement. Southern Company, the traditional operating companies, and Southern Power may also borrow through various other arrangements with banks. Short-term borrowings are included in notes payable in the balance sheets.

Details of short-term borrowings were as follows:

	Short-term Debt at March 31, 2016				Short-term Debt During the Period(*)
	Amount Outstanding		Weighted Average Interest Rate		Average Amount Outstanding		Weighted Average Interest Rate		Maximum Amount Outstanding
	(in millions)				(in millions)				(in millions)
Commercial paper	$	757	0.8	%	$	853	0.8	%	$	1,233
Short-term bank debt	25		2.1	%	375		1.9	%	500
Total	$	782	0.9	%	$	1,228	1.0	%

(*) Average and maximum amounts are based upon daily balances during the three-month period ended March 31, 2016.

In addition to the short-term borrowings in the table above, the Project Credit Facilities had total amounts outstanding as of March 31, 2016 of $413 million at a weighted average interest rate of 1.99%. For the three months ended March 31, 2016, these credit agreements had a maximum amount outstanding of $413 million, and an average amount outstanding of $260 million at a weighted average interest rate of 1.99%.

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

31

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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/or Baa2 or below. These contracts are for physical electricity purchases and sales, fuel purchases, fuel transportation and storage, energy price risk management, transmission, interest rate management, and construction of new generation at Plant Vogtle Units 3 and 4.

The maximum potential collateral requirements under these contracts at March 31, 2016 were as follows:

Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB and/or Baa2	$	12
At BBB- and/or Baa3	$	511
Below BBB- and/or Baa3	$	2,335

Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of Southern Company and its subsidiaries to access capital markets, and would be likely to impact the cost at which they do so.

Financing Activities

During the first three months of 2016, Southern Company issued approximately 6.6 million shares of common stock primarily through the employee equity compensation plan and received proceeds of approximately $270 million. Southern Company may satisfy its obligations with respect to the plans in several ways, including through using newly issued shares or treasury shares or acquiring shares on the open market through independent plan administrators.

The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first three months of 2016:

Company(a)	Senior Note Issuances		Senior Note Maturities and Redemptions		Revenue Bond Maturities, Redemptions, and Repurchases		Other Long-Term Debt Issuances			Other Long-Term Debt Redemptions and Maturities(b)
	(in millions)
Alabama Power	$	400	$	200	$	—	$	45		$	—
Georgia Power	650		250		4		—			1
Mississippi Power	—		—		—		1,100			426
Southern Power	—		—		—		2			3
Other	—		—		—		—			4
Elimination(c)	—		—		—		(200		)	—
Total	$	1,050	$	450	$	4	$	947		$	434

(a) Southern Company and Gulf Power did not issue or redeem any long-term debt during the first three months of 2016.    

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

(c) Intercompany loans from Southern Company to Mississippi Power eliminated in Southern Company's Consolidated Financial Statements.

32

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

In February 2016, Southern Company entered into forward-starting interest rate swaps to hedge exposure to interest rate changes related to anticipated debt issuances. The notional amount of the swaps totaled $700 million.

Except as described herein, Southern Company's subsidiaries used the proceeds of the debt issuances shown in the table above for their redemptions and maturities shown in the table above, to repay short-term indebtedness, and for general corporate purposes, including their continuous construction programs and, for Southern Power, its growth strategy.

On March 8, 2016, Mississippi Power entered into an unsecured term loan agreement for an aggregate amount of $1.2 billion to repay existing indebtedness and for other general corporate purposes. Mississippi Power borrowed $900 million under the term loan agreement and has the right to borrow the remaining $300 million on or before October 15, 2016, upon satisfaction of certain customary conditions. Mississippi Power used the initial proceeds to repay $900 million in maturing bank notes on March 8, 2016 and expects the remaining $300 million to be used to repay senior notes maturing in October 2016. The term loan pursuant to this agreement matures on April 1, 2018 and bears interest based on one-month LIBOR.

During the three months ended March 31, 2016, Southern Power's subsidiaries borrowed $276 million pursuant to the Project Credit Facilities at a weighted average interest rate of 1.99%.

Subsequent to March 31, 2016, Southern Power's subsidiaries borrowed $187 million pursuant to the Project Credit Facilities at a weighted average interest rate of 1.93%.

Also subsequent to March 31, 2016, Gulf Power announced the redemption in May 2016 of $125 million aggregate principal amount of its Series 2011A 5.75% Senior Notes due June 1, 2051.

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

33

PART I

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

During the three months ended March 31, 2016, 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 on Form 10-Q, 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, as amended). 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 over financial reporting.

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, as amended) during the first quarter 2016 that have materially affected or are reasonably likely to materially affect Southern Company's, Alabama Power's, Georgia Power's, Gulf Power's, Mississippi Power's, or Southern Power Company's internal control over financial reporting.

34

ALABAMA POWER COMPANY

35

ALABAMA POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended March 31,
	2016			2015
	(in millions)
Operating Revenues:
Retail revenues	$	1,193		$	1,268
Wholesale revenues, non-affiliates	63			65
Wholesale revenues, affiliates	22			15
Other revenues	53			53
Total operating revenues	1,331			1,401
Operating Expenses:
Fuel	268			310
Purchased power, non-affiliates	36			41
Purchased power, affiliates	33			53
Other operations and maintenance	392			399
Depreciation and amortization	172			158
Taxes other than income taxes	97			94
Total operating expenses	998			1,055
Operating Income	333			346
Other Income and (Expense):
Allowance for equity funds used during construction	10			15
Interest expense, net of amounts capitalized	(73		)	(65		)
Other income (expense), net	(8		)	(4		)
Total other income and (expense)	(71		)	(54		)
Earnings Before Income Taxes	262			292
Income taxes	103			113
Net Income	159			179
Dividends on Preferred and Preference Stock	4			10
Net Income After Dividends on Preferred and Preference Stock	$	155		$	169

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended March 31,
	2016			2015
	(in millions)
Net Income	$	159		$	179
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(1) and $(2), respectively	(2		)	(4		)
Reclassification adjustment for amounts included in net income, net of tax of $1 and $-, respectively	1			—
Total other comprehensive income (loss)	(1		)	(4		)
Comprehensive Income	$	158		$	175

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

36

ALABAMA POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Three Months Ended March 31,
	2016			2015
	(in millions)
Operating Activities:
Net income	$	159		$	179
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	211			196
Deferred income taxes	68			16
Allowance for equity funds used during construction	(10		)	(15		)
Other, net	(3		)	2
Changes in certain current assets and liabilities —
-Receivables	191			(3		)
-Fossil fuel stock	(27		)	—
-Materials and supplies	(8		)	12
-Other current assets	(79		)	(80		)
-Accounts payable	(143		)	(229		)
-Accrued taxes	64			246
-Accrued compensation	(75		)	(89		)
-Retail fuel cost over recovery	(1		)	34
-Other current liabilities	(8		)	21
Net cash provided from operating activities	339			290
Investing Activities:
Property additions	(313		)	(325		)
Nuclear decommissioning trust fund purchases	(105		)	(129		)
Nuclear decommissioning trust fund sales	105			129
Cost of removal, net of salvage	(31		)	(13		)
Change in construction payables	(15		)	34
Other investing activities	(9		)	(9		)
Net cash used for investing activities	(368		)	(313		)
Financing Activities:
Proceeds —
Senior notes issuances	400			550
Capital contributions from parent company	236			6
Other long-term debt issuances	45			—
Redemptions — Senior notes	(200		)	(250		)
Payment of common stock dividends	(191		)	(143		)
Other financing activities	(11		)	(18		)
Net cash provided from financing activities	279			145
Net Change in Cash and Cash Equivalents	250			122
Cash and Cash Equivalents at Beginning of Period	194			273
Cash and Cash Equivalents at End of Period	$	444		$	395
Supplemental Cash Flow Information:
Cash paid (received) during the period for --
Interest (net of $4 and $5 capitalized for 2016 and 2015, respectively)	$	76		$	68
Income taxes, net	(162		)	(136		)
Noncash transactions — Accrued property additions at end of period	106			41

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

37

ALABAMA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Assets	At March 31, 2016			At December 31, 2015
	(in millions)
Current Assets:
Cash and cash equivalents	$	444		$	194
Receivables —
Customer accounts receivable	311			332
Unbilled revenues	113			119
Under recovered regulatory clause revenues	22			43
Income taxes receivable, current	—			142
Other accounts and notes receivable	25			20
Affiliated companies	38			50
Accumulated provision for uncollectible accounts	(10		)	(10		)
Fossil fuel stock, at average cost	266			239
Materials and supplies, at average cost	406			398
Vacation pay	67			66
Prepaid expenses	129			83
Other regulatory assets, current	99			115
Other current assets	10			10
Total current assets	1,920			1,801
Property, Plant, and Equipment:
In service	25,187			24,750
Less accumulated provision for depreciation	8,791			8,736
Plant in service, net of depreciation	16,396			16,014
Nuclear fuel, at amortized cost	359			363
Construction work in progress	550			801
Total property, plant, and equipment	17,305			17,178
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	68			71
Nuclear decommissioning trusts, at fair value	746			737
Miscellaneous property and investments	99			96
Total other property and investments	913			904
Deferred Charges and Other Assets:
Deferred charges related to income taxes	520			522
Deferred under recovered regulatory clause revenues	105			99
Other regulatory assets, deferred	1,105			1,114
Other deferred charges and assets	109			103
Total deferred charges and other assets	1,839			1,838
Total Assets	$	21,977		$	21,721

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

38

ALABAMA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholder's Equity	At March 31, 2016			At December 31, 2015
	(in millions)
Current Liabilities:
Securities due within one year	$	200		$	200
Accounts payable —
Affiliated	258			278
Other	271			410
Customer deposits	88			88
Accrued taxes —
Accrued income taxes	11			—
Other accrued taxes	62			38
Accrued interest	65			73
Accrued vacation pay	55			55
Accrued compensation	47			119
Liabilities from risk management activities	37			55
Other regulatory liabilities, current	175			240
Other current liabilities	39			39
Total current liabilities	1,308			1,595
Long-term Debt	6,894			6,654
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	4,306			4,241
Deferred credits related to income taxes	69			70
Accumulated deferred investment tax credits	116			118
Employee benefit obligations	377			388
Asset retirement obligations	1,461			1,448
Other cost of removal obligations	705			722
Other regulatory liabilities, deferred	119			136
Deferred over recovered regulatory clause revenues	64			—
Other deferred credits and liabilities	78			76
Total deferred credits and other liabilities	7,295			7,199
Total Liabilities	15,497			15,448
Redeemable Preferred Stock	85			85
Preference Stock	196			196
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	2,585			2,341
Retained earnings	2,425			2,461
Accumulated other comprehensive loss	(33		)	(32		)
Total common stockholder's equity	6,199			5,992
Total Liabilities and Stockholder's Equity	$	21,977		$	21,721

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

39

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

FIRST QUARTER 2016 vs. FIRST QUARTER 2015

OVERVIEW

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

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

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

RESULTS OF OPERATIONS

Net Income

First Quarter 2016 vs. First Quarter 2015
(change in millions)	(% change)
$(14)	(8.3)

Alabama Power's net income after dividends on preferred and preference stock for the first quarter 2016 was $155 million compared to $169 million for the corresponding period in 2015. The decrease was primarily related to a decrease in revenue primarily due to milder weather in the first quarter 2016 as compared to the corresponding period in 2015, an increase in interest expense, and a decrease in AFUDC. These decreases were partially offset by an increase in revenues under Rate CNP Compliance and a decrease in dividends on preferred and preference stock.

Retail Revenues

First Quarter 2016 vs. First Quarter 2015
(change in millions)	(% change)
$(75)	(5.9)

In the first quarter 2016, retail revenues were $1.19 billion compared to $1.27 billion for the corresponding period in 2015.

40

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Details of the changes in retail revenues were as follows:

	First Quarter 2016
	(in millions)			(% change)
Retail – prior year	$	1,268
Estimated change resulting from –
Rates and pricing	33			2.6
Sales growth	8			0.6
Weather	(45		)	(3.5	)
Fuel and other cost recovery	(71		)	(5.6	)
Retail – current year	$	1,193		(5.9	)%

Revenues associated with changes in rates and pricing increased in the first quarter 2016 when compared to the corresponding period in 2015 primarily due to increased revenues under Rate CNP Compliance associated with increases in the average net investments. See Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information.

Revenues attributable to sales growth increased in the first quarter 2016 when compared to the corresponding period in 2015. Weather-adjusted residential and commercial KWH energy sales increased 2.3% and 0.9%, respectively, for the first quarter 2016 when compared to the corresponding period in 2015 as a result of increased customer demand. Industrial KWH energy sales decreased 3.5% for the first quarter 2016 when compared to the corresponding period in 2015 as a result of a decrease in demand resulting from changes in production levels primarily in the pipelines, primary metals, and chemicals sectors. A strong dollar, low oil prices, and weak global growth conditions have constrained growth in the industrial sector.

Revenues resulting from changes in weather decreased in the first quarter 2016 due to milder weather experienced in Alabama Power's service territory compared to the corresponding period in 2015. For the first quarter 2016, the resulting decreases were 6.6% and 2.2% for residential and commercial sales revenue, respectively.

Fuel and other cost recovery revenues decreased in the first quarter 2016 when compared to the corresponding period in 2015 primarily due to a decrease in KWH generation and a decrease in the average cost of fuel. Electric rates include provisions to recognize the full recovery of fuel costs, purchased power costs, PPAs certificated by the Alabama PSC, and costs associated with the 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. See Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information.

Wholesale Revenues – Affiliates

First Quarter 2016 vs. First Quarter 2015
(change in millions)	(% change)
$7	46.7

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

In the first quarter 2016, wholesale revenues from sales to affiliates were $22 million compared to $15 million for the corresponding period in 2015. KWH sales to affiliates increased 78.5% primarily as a result of higher available hydro generation and lower natural gas prices.

41

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Fuel and Purchased Power Expenses

	First Quarter 2016 vs. First Quarter 2015
	(change in millions)			(% change)
Fuel	$	(42	)	(13.5)
Purchased power – non-affiliates	(5		)	(12.2)
Purchased power – affiliates	(20		)	(37.7)
Total fuel and purchased power expenses	$	(67	)

In the first quarter 2016, total fuel and purchased power expenses were $337 million compared to $404 million for the corresponding period in 2015. The decrease was primarily due to a $33 million decrease related to the volume of KWHs purchased, a $23 million decrease related to the volume of KWHs generated, and a $19 million decrease in the average cost of fuel. These decreases were partially offset by an $8 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 clause. Alabama Power, along with the Alabama PSC, continuously monitors the under/over recovered balance to determine whether adjustments to billing rates are required. See Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Rate ECR" in Item 8 of the Form 10-K for additional information.

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

	First Quarter 2016	First Quarter 2015
Total generation (billions of KWHs)	15	15
Total purchased power (billions of KWHs)	1	2
Sources of generation (percent) —
Coal	40	47
Nuclear	27	26
Gas	19	19
Hydro	14	8
Cost of fuel, generated (cents per net KWH) —
Coal	2.86	2.89
Nuclear	0.77	0.80
Gas	2.46	3.03
Average cost of fuel, generated (cents per net KWH)(a)	2.12	2.33
Average cost of purchased power (cents per net KWH)(b)	5.16	4.60

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

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

Fuel

In the first quarter 2016, fuel expense was $268 million compared to $310 million for the corresponding period in 2015. The decrease was primarily due to a 18.8% decrease in the average cost of natural gas per KWH generated, which excludes fuel associated with tolling agreements, and a 15.0% decrease in the volume of KWHs generated by coal, partially offset by a 6.8% increase in the volume of KWHs generated by natural gas.

42

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Purchased Power – Non-Affiliates

In the first quarter 2016, purchased power expense from non-affiliates was $36 million compared to $41 million for the corresponding period in 2015. The decrease was related to a 10.7% decrease in the amount of energy purchased due to the availability of lower cost generation as a result of more rainfall for hydro generation and lower natural gas prices.

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

Purchased Power – Affiliates

In the first quarter 2016, purchased power expense from affiliates was $33 million compared to $53 million for the corresponding period in 2015. The decrease was related to a 48.2% decrease in the amount of energy purchased due to milder weather and the availability of lower cost generation as a result of more rainfall for hydro generation and lower natural gas prices. The decrease was partially offset by a 20.6% increase in the average cost of purchased power per KWH from affiliates.

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

Other Operations and Maintenance Expenses

First Quarter 2016 vs. First Quarter 2015
(change in millions)	(% change)
$(7)	(1.8)

In the first quarter 2016, other operations and maintenance expenses were $392 million compared to $399 million for the corresponding period in 2015. The decrease was primarily due to a decrease of $14 million in steam generation costs primarily due to scheduled outage costs. This decrease was partially offset by a $6 million increase in nuclear generation costs primarily due to outage amortization and materials costs.

Depreciation and Amortization

First Quarter 2016 vs. First Quarter 2015
(change in millions)	(% change)
$14	8.9

In the first quarter 2016, depreciation and amortization was $172 million compared to $158 million for the corresponding period in 2015. The increase was primarily the result of an increase in depreciation of compliance related steam equipment. See Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Rate CNP" in Item 8 of the Form 10-K for additional information.

Allowance for Equity Funds Used During Construction

First Quarter 2016 vs. First Quarter 2015
(change in millions)	(% change)
$(5)	(33.3)

In the first quarter 2016, AFUDC equity was $10 million compared to $15 million for the corresponding period in 2015. The decrease was primarily associated with capital projects being placed in service for environmental and steam generation in 2016.

43

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Interest Expense, Net of Amounts Capitalized

First Quarter 2016 vs. First Quarter 2015
(change in millions)	(% change)
$8	12.3

In the first quarter 2016, interest expense, net of amounts capitalized was $73 million compared to $65 million for the corresponding period in 2015. The increase was primarily due to timing of debt issuances, maturities, and redemptions.

Income Taxes

First Quarter 2016 vs. First Quarter 2015
(change in millions)	(% change)
$(10)	(8.8)

In the first quarter 2016, income taxes were $103 million compared to $113 million for the corresponding period in 2015. The decrease was primarily due to lower pre-tax earnings.

Dividends on Preferred and Preference Stock

First Quarter 2016 vs. First Quarter 2015
(change in millions)	(% change)
$(6)	(60.0)

In the first quarter 2016, dividends on preferred and preference stock were $4 million compared to $10 million for the corresponding period in 2015. The decrease was primarily due to the redemption in May 2015 of certain series of preferred and preference stock. See Note 6 to the financial statements of Alabama Power under "Redeemable Preferred Stock" in Item 8 of the Form 10-K for additional information.

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 are subject to a number of factors. These factors include weather, competition, new energy contracts with other utilities, energy conservation practiced by customers, the use of alternative energy sources by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in Alabama Power's service territory. Demand for electricity is primarily driven by economic growth. The pace of economic growth and electricity demand may be affected by changes in regional and global economic conditions, which may impact future earnings. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Alabama Power in Item 7 of the Form 10-K.

Environmental Matters

Compliance costs related to federal and state environmental statutes and regulations could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified, as compliance plans are revised or updated, and as legal challenges to rules are completed. Environmental compliance costs are

44

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

recovered through Rate CNP Compliance. See Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Rate CNP" in Item 8 of the Form 10-K for additional information. Further, higher costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively affect results of operations, cash flows, and financial condition. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Alabama Power in Item 7 and Note 3 to the financial statements of Alabama Power under "Environmental Matters" in Item 8 of the Form 10-K for additional information.

Environmental Statutes and Regulations

Air Quality

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Air Quality" of Alabama Power in Item 7 of the Form 10-K for additional information regarding the EPA's final MATS rule and regional haze regulations.

On April 25, 2016, in response to a June 2015 U.S. Supreme Court opinion, the EPA published its supplemental finding regarding consideration of costs in support of the MATS rule. This finding does not impact MATS rule compliance requirements, costs, or deadlines, and all Alabama Power units that are subject to the MATS rule have completed the measures necessary to achieve compliance with the MATS rule by the applicable deadlines.

Also on April 25, 2016, the EPA issued proposed revisions to the regional haze regulations. The ultimate impact of the proposed revisions will depend on their ultimate adoption, implementation, and any legal challenges and cannot be determined at this time.

FERC Matters

See BUSINESS – REGULATION – "Federal Power Act" in Item 1 of the Form 10-K for a discussion of Alabama Power's hydroelectric developments on the Coosa River. On April 21, 2016, the FERC issued an order granting in part and denying in part Alabama Power's rehearing request of the new license for Alabama Power's seven hydroelectric developments on the Coosa River. The order also denied rehearing requests filed by Alabama Rivers Alliance, American Rivers, the Georgia Environmental Protection Division, and the Atlanta Regional Commission. The ultimate outcome of this matter cannot be determined at this time.

Retail Regulatory Matters

Alabama Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Alabama PSC. Alabama Power currently recovers its costs from the regulated retail business primarily through its Rate RSE, Rate CNP Compliance, rate energy cost recovery, and natural disaster reserve rate. In addition, the Alabama PSC issues accounting orders to address current events impacting Alabama Power. See Notes 1 and 3 to the financial statements of Alabama Power under "Nuclear Outage Accounting Order" and "Retail Regulatory Matters," respectively, in Item 8 of the Form 10-K for additional information regarding Alabama Power's rate mechanisms and accounting orders. The recovery balance of each regulatory clause for Alabama Power is reported in Note (B) to the Condensed Financial Statements herein.

Other Matters

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

45

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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

Recently Issued Accounting Standards

On February 25, 2016, the FASB issued ASU No. 2016-02, Leases(Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. Alabama Power is currently evaluating the new standard and has not yet determined its ultimate impact; however, adoption of ASU 2016-02 is expected to have a significant impact on Alabama Power's balance sheet.

On March 30, 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation(Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions. Most significantly, entities are required to recognize all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation as income tax expense or benefit in the income statement. Alabama Power currently recognizes any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation in additional paid-in capital. ASU 2016-09 is effective for fiscal years beginning after December 15, 2016, with early adoption permitted. Alabama Power is currently evaluating the new standard and has not yet determined its ultimate impact.

FINANCIAL CONDITION AND LIQUIDITY

Overview

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Alabama Power in Item 7 of the Form 10-K for additional information. Alabama Power's financial condition remained stable at March 31, 2016. 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 $339 million for the first three months of 2016, an increase of

46

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

$49 million as compared to the first three months of 2015. The increase in net cash provided from operating activities was primarily due to the timing of vendor payments and deferred income taxes, partially offset by the collection of fuel cost recovery revenues and timing of fossil fuel stock purchases. Net cash used for investing activities totaled $368 million for the first three months of 2016 primarily due to gross property additions related to environmental, distribution, steam generation, and transmission. Net cash provided from financing activities totaled $279 million for the first three months of 2016 primarily due to issuances of long-term debt and a capital contribution from Southern Company, partially offset by a redemption of long-term debt and a common stock dividend payment. Fluctuations in cash flow from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes for the first three months of 2016 include increases of $250 million in cash and cash equivalents, $244 million in additional paid-in capital due to capital contributions from Southern Company, $240 million in long-term debt primarily due to the issuance of additional senior notes, and $127 million in property, plant, and equipment, primarily due to additions to environmental, transmission, distribution, and nuclear generation. Other significant changes include decreases of $142 million in income taxes receivable following the receipt of a federal income tax refund and $139 million in accounts payable primarily due to the timing of vendor payments.

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 $200 million will be required through March 31, 2017 to fund maturities of long-term debt.

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

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

Sources of Capital

Alabama Power plans to obtain the funds to meet its future capital needs through operating cash flows, short-term debt, term loans, external security issuances, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, 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.

47

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

At March 31, 2016, Alabama Power had approximately $444 million of cash and cash equivalents. Committed credit arrangements with banks at March 31, 2016 were as follows:

Expires										Due Within One Year
2016		2018		2020		Total		Unused		Term Out		No Term Out
(in millions)						(in millions)				(in millions)
$	40	$	500	$	800	$	1,340	$	1,340	$	—	$	40

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

Most of these bank credit arrangements, as well as Alabama Power's term loan arrangements, contain covenants that limit debt levels and contain cross acceleration provisions to other indebtedness (including guarantee obligations) of Alabama Power. Such cross acceleration provisions to other indebtedness would trigger an event of default if Alabama Power defaulted on indebtedness, the payment of which was then accelerated. Alabama Power is currently in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowings.

Subject to applicable market conditions, Alabama Power expects to renew or replace its bank credit arrangements as needed, prior to expiration. In connection therewith, Alabama Power may extend the maturity dates and/or increase or decrease the lending commitments thereunder.

A portion of the unused credit with banks is allocated to provide liquidity support to Alabama Power's pollution control revenue bonds and commercial paper borrowings. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of March 31, 2016 was approximately $810 million. In addition, at March 31, 2016, Alabama Power had $167 million of fixed rate pollution control revenue bonds outstanding that were required to be reoffered within the next 12 months.

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

Details of short-term borrowings were as follows:

	Short-term Debt During the Period(*)
	Average Amount Outstanding		Weighted Average Interest Rate		Maximum Amount Outstanding
	(in millions)				(in millions)
Commercial paper	$	19	0.6	%	$	100

(*) Average and maximum amounts are based upon daily balances during the three-month period ended March 31, 2016. No short-term debt was outstanding at March 31, 2016.

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

48

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 BBB and/or Baa2 or below. These contracts are primarily for physical electricity purchases, fuel purchases, fuel transportation and storage, energy price risk management, and transmission. The maximum potential collateral requirements under these contracts at March 31, 2016 were as follows:

Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB and/or Baa2	$	1
At BBB- and/or Baa3	$	2
Below BBB- and/or Baa3	$	349

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, a credit rating downgrade could impact the ability of Alabama Power to access capital markets, and would be likely to impact the cost at which it does so.

Financing Activities

In January 2016, Alabama Power issued $400 million aggregate principal amount of Series 2016A 4.30% Senior Notes due January 2, 2046. The proceeds were used to repay at maturity $200 million aggregate principal amount of Alabama Power's Series FF 5.20% Senior Notes due January 15, 2016 and for general corporate purposes, including Alabama Power's continuous construction program.

In March 2016, Alabama Power entered into three bank term loan agreements with maturity dates of March 2021, in an aggregate principal amount of $45 million, one of which bears interest at 2.38% per annum and two of which bear interest based on three-month LIBOR.

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

49

GEORGIA POWER COMPANY

50

GEORGIA POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended March 31,
	2016			2015
	(in millions)
Operating Revenues:
Retail revenues	$	1,717		$	1,814
Wholesale revenues, non-affiliates	41			68
Wholesale revenues, affiliates	5			8
Other revenues	109			88
Total operating revenues	1,872			1,978
Operating Expenses:
Fuel	376			526
Purchased power, non-affiliates	83			60
Purchased power, affiliates	139			149
Other operations and maintenance	457			474
Depreciation and amortization	211			216
Taxes other than income taxes	97			99
Total operating expenses	1,363			1,524
Operating Income	509			454
Other Income and (Expense):
Interest expense, net of amounts capitalized	(94		)	(89		)
Other income (expense), net	17			15
Total other income and (expense)	(77		)	(74		)
Earnings Before Income Taxes	432			380
Income taxes	160			140
Net Income	272			240
Dividends on Preferred and Preference Stock	4			4
Net Income After Dividends on Preferred and Preference Stock	$	268		$	236

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended March 31,
	2016		2015
	(in millions)
Net Income	$	272	$	240
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $- and $(9), respectively	—		(14		)
Reclassification adjustment for amounts included in net income, net of tax of $- and $-, respectively	1		—
Total other comprehensive income (loss)	1		(14		)
Comprehensive Income	$	273	$	226

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

51

GEORGIA POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Three Months Ended March 31,
	2016			2015
	(in millions)
Operating Activities:
Net income	$	272		$	240
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	261			256
Deferred income taxes	55			(7		)
Allowance for equity funds used during construction	(14		)	(15		)
Deferred expenses	38			33
Other, net	(9		)	4
Changes in certain current assets and liabilities —
-Receivables	155			166
-Fossil fuel stock	36			67
-Prepaid income taxes	38			170
-Other current assets	12			(13		)
-Accounts payable	4			(261		)
-Accrued taxes	(235		)	(217		)
-Accrued compensation	(66		)	(81		)
-Other current liabilities	16			21
Net cash provided from operating activities	563			363
Investing Activities:
Property additions	(553		)	(422		)
Nuclear decommissioning trust fund purchases	(211		)	(161		)
Nuclear decommissioning trust fund sales	206			155
Cost of removal, net of salvage	(15		)	(16		)
Change in construction payables, net of joint owner portion	(101		)	37
Prepaid long-term service agreements	(11		)	(9		)
Other investing activities	(4		)	11
Net cash used for investing activities	(689		)	(405		)
Financing Activities:
Increase (decrease) in notes payable, net	(158		)	434
Proceeds —
Capital contributions from parent company	218			11
Senior notes issuances	650			—
Short-term borrowings	—			250
Redemptions and repurchases —
Pollution control revenue bonds	(4		)	—
Senior notes	(250		)	—
Payment of common stock dividends	(326		)	(259		)
Other financing activities	(11		)	(5		)
Net cash provided from financing activities	119			431
Net Change in Cash and Cash Equivalents	(7		)	389
Cash and Cash Equivalents at Beginning of Period	67			24
Cash and Cash Equivalents at End of Period	$	60		$	413
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $5 and $6 capitalized for 2016 and 2015, respectively)	$	86		$	79
Income taxes, net	(88		)	(34		)
Noncash transactions — Accrued property additions at end of period	290			177

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

52

GEORGIA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Assets	At March 31, 2016			At December 31, 2015
	(in millions)
Current Assets:
Cash and cash equivalents	$	60		$	67
Receivables —
Customer accounts receivable	509			541
Unbilled revenues	182			188
Joint owner accounts receivable	73			227
Income taxes receivable, current	—			114
Other accounts and notes receivable	37			57
Affiliated companies	16			18
Accumulated provision for uncollectible accounts	(2		)	(2		)
Fossil fuel stock, at average cost	366			402
Materials and supplies, at average cost	463			449
Vacation pay	92			91
Prepaid income taxes	118			156
Other regulatory assets, current	126			123
Other current assets	61			92
Total current assets	2,101			2,523
Property, Plant, and Equipment:
In service	32,318			31,841
Less accumulated provision for depreciation	11,045			10,903
Plant in service, net of depreciation	21,273			20,938
Other utility plant, net	158			171
Nuclear fuel, at amortized cost	582			572
Construction work in progress	4,817			4,775
Total property, plant, and equipment	26,830			26,456
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	60			64
Nuclear decommissioning trusts, at fair value	793			775
Miscellaneous property and investments	43			43
Total other property and investments	896			882
Deferred Charges and Other Assets:
Deferred charges related to income taxes	680			679
Other regulatory assets, deferred	2,138			2,152
Other deferred charges and assets	157			173
Total deferred charges and other assets	2,975			3,004
Total Assets	$	32,802		$	32,865

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

53

GEORGIA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholder's Equity	At March 31, 2016			At December 31, 2015
	(in millions)
Current Liabilities:
Securities due within one year	$	458		$	712
Notes payable	—			158
Accounts payable —
Affiliated	370			411
Other	549			750
Customer deposits	266			264
Accrued taxes —
Accrued income taxes	—			12
Other accrued taxes	101			325
Accrued interest	102			99
Accrued vacation pay	62			62
Accrued compensation	60			142
Asset retirement obligations, current	184			179
Other current liabilities	211			181
Total current liabilities	2,363			3,295
Long-term Debt	10,268			9,616
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	5,686			5,627
Deferred credits related to income taxes	105			105
Accumulated deferred investment tax credits	201			204
Employee benefit obligations	930			949
Asset retirement obligations, deferred	1,699			1,737
Other deferred credits and liabilities	395			347
Total deferred credits and other liabilities	9,016			8,969
Total Liabilities	21,647			21,880
Preferred Stock	45			45
Preference Stock	221			221
Common Stockholder's Equity:
Common stock, without par value —
Authorized — 20,000,000 shares
Outstanding — 9,261,500 shares	398			398
Paid-in capital	6,504			6,275
Retained earnings	4,002			4,061
Accumulated other comprehensive loss	(15		)	(15		)
Total common stockholder's equity	10,889			10,719
Total Liabilities and Stockholder's Equity	$	32,802		$	32,865

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

54

GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

FIRST QUARTER 2016 vs. FIRST QUARTER 2015

OVERVIEW

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

Many factors affect the opportunities, challenges, and risks of Georgia Power's business of selling electricity. These factors include the ability to maintain a constructive regulatory environment, to maintain and grow energy sales, and to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand growth, increasingly stringent environmental standards, reliability, and fuel. In addition, construction continues on Plant Vogtle Units 3 and 4. Georgia Power will own a 45.7% interest in these two nuclear generating units to increase its generation diversity and meet future supply needs. Georgia Power has various regulatory mechanisms that operate to address cost recovery. Effectively operating pursuant to these regulatory mechanisms andappropriately balancing required costs and capital expenditures with customer prices will continue to challenge Georgia Power for the foreseeable future.

Pursuant to the terms and conditions of a settlement agreement related to Southern Company's proposed acquisition of AGL Resources approved by the Georgia PSC on April 14, 2016, Georgia Power's 2013 ARP will continue in effect until December 31, 2019, and Georgia Power will be required to file its next base rate case by July 1, 2019. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters" herein for additional information.

Georgia Power continues to focus on several key performance indicators. These indicators include, but are not limited to, customer satisfaction, plant availability, system reliability, the execution of major construction projects, and net income after dividends on preferred and preference stock. For additional information on these indicators, see MANAGEMENT'S DISCUSSION AND ANALYSIS – OVERVIEW – "Key Performance Indicators" of Georgia Power in Item 7 of the Form 10-K.

RESULTS OF OPERATIONS

Net Income

First Quarter 2016 vs. First Quarter 2015
(change in millions)	(% change)
$32	13.6

Georgia Power's net income after dividends on preferred and preference stock for the first quarter 2016 was $268 million compared to $236 million for the corresponding period in 2015. The increase in the first quarter 2016 was primarily due to an increase in retail base revenues effective January 1, 2016, as authorized by the Georgia PSC, and lower non-fuel operating expenses, partially offset by lower retail revenues due to milder weather in the first quarter 2016 as compared to the corresponding period in 2015.

Retail Revenues

First Quarter 2016 vs. First Quarter 2015
(change in millions)	(% change)
$(97)	(5.3)

In the first quarter 2016, retail revenues were $1.72 billion compared to $1.81 billion for the corresponding period in 2015.

55

GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Details of the changes in retail revenues were as follows:

	First Quarter 2016
	(in millions)			(% change)
Retail – prior year	$	1,814
Estimated change resulting from –
Rates and pricing	43			2.4
Sales growth	8			0.4
Weather	(32		)	(1.8	)
Fuel cost recovery	(116		)	(6.4	)
Retail – current year	$	1,717		(5.4	)%

Revenues associated with changes in rates and pricing increased in the first quarter 2016 when compared to the corresponding period in 2015 primarily due to increases in base tariffs approved under the 2013 ARP and the NCCR tariff, all effective January 1, 2016. See Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Rate Plans" and " – Nuclear Construction" in Item 8 of the Form 10-K for additional information.

Revenues attributable to changes in sales increased in the first quarter 2016 when compared to the corresponding period in 2015. Weather-adjusted residential KWH sales increased 0.5%, weather-adjusted commercial KWH sales increased 0.8%, and weather-adjusted industrial KWH sales increased 1.4% in the first quarter 2016 when compared to the corresponding period in 2015. Increases of approximately 24,000 residential customers and approximately 3,000 commercial customers since March 31, 2015 contributed to the increases in weather-adjusted residential KWH sales and weather-adjusted commercial KWH sales, respectively. Increased demand in the paper, rubber, and non-manufacturing sectors was the main contributor to the increase in weather-adjusted industrial KWH sales, partially offset by decreased demand in the pipeline, military, and textiles sectors.

Fuel revenues and costs are allocated between retail and wholesale jurisdictions. Retail fuel cost recovery revenues decreased $116 million in the first quarter 2016 when compared to the corresponding period in 2015 primarily due to lower coal and natural gas prices, more available hydro generation, and lower energy sales resulting from milder weather in the first quarter 2016 as compared to the corresponding period in 2015. Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these fuel cost recovery provisions, fuel revenues generally equal fuel expenses and do not affect net income. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Fuel Cost Recovery" herein for additional information.

Wholesale Revenues – Non-Affiliates

First Quarter 2016 vs. First Quarter 2015
(change in millions)	(% change)
$(27)	(39.7)

Wholesale revenues from sales to non-affiliates consist of PPAs and short-term opportunity sales. Wholesale revenues from PPAs have both capacity and energy components. Wholesale capacity revenues from PPAs are recognized either on a levelized basis over the appropriate contract period or the amounts billable under the contract terms and provide for recovery of fixed costs and a return on investment. Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Georgia Power's and the Southern Company system's generation, demand for energy within the Southern Company system's service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not

56

GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

have a significant impact on net income. Short-term opportunity sales are made at market-based rates that generally provide a margin above Georgia Power's variable cost to produce the energy.

In the first quarter 2016, wholesale revenues from sales to non-affiliates were $41 million compared to $68 million for the corresponding period in 2015 related to a $14 million decrease in energy revenues and a $13 million decrease in capacity revenues. The decrease in energy revenues was primarily due to lower fuel prices, including higher hydro generation availability. The decrease in capacity revenues reflects the retirement of 14 coal-fired generating units after March 31, 2015 as a result of Georgia Power's environmental compliance strategy.

Wholesale Revenues – Affiliates

First Quarter 2016 vs. First Quarter 2015
(change in millions)	(% change)
$(3)	(37.5)

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

In the first quarter 2016, wholesale revenues from sales to affiliates were $5 million compared to $8 million for the corresponding period in 2015. The decrease was due to lower fuel prices and a 44.4% decrease in KWH sales in the first quarter 2016, primarily due to the higher cost of Georgia Power-owned generation as compared to the market cost of available energy.

Other Revenues

First Quarter 2016 vs. First Quarter 2015
(change in millions)	(% change)
$21	23.9

In the first quarter 2016, other revenues were $109 million compared to $88 million for the corresponding period in 2015. The increase was primarily due to a $14 million increase related to an adjustment for customer temporary facilities service revenues and a $3 million increase in outdoor lighting revenues.

Fuel and Purchased Power Expenses

	First Quarter 2016 vs. First Quarter 2015
	(change in millions)			(% change)
Fuel	$	(150	)	(28.5	)
Purchased power – non-affiliates	23			38.3
Purchased power – affiliates	(10		)	(6.7	)
Total fuel and purchased power expenses	$	(137	)

In the first quarter 2016, total fuel and purchased power expenses were $598 million compared to $735 million in the corresponding period in 2015. The decrease in the first quarter 2016 was due to a decrease of $89 million in the average cost of fuel and purchased power related to lower coal and natural gas prices and more rainfall for hydro generation and a net decrease of $48 million in the volume of KWHs generated and purchased due to milder weather as compared to the corresponding period in 2015 resulting in lower 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

57

GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Fuel Cost Recovery" herein for additional information.

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

	First Quarter 2016	First Quarter 2015
Total generation (billions of KWHs)	16	17
Total purchased power (billions of KWHs)	6	6
Sources of generation (percent) —
Coal	30	34
Nuclear	23	22
Gas	42	42
Hydro	5	2
Cost of fuel, generated (cents per net KWH) —
Coal	3.56	4.71
Nuclear	0.86	0.54
Gas	2.01	2.63
Average cost of fuel, generated (cents per net KWH)	2.22	2.86
Average cost of purchased power (cents per net KWH)(*)	4.32	4.39

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

Fuel

In the first quarter 2016, fuel expense was $376 million compared to $526 million in the corresponding period in 2015. The decrease was primarily due to a 22.4% decrease in the average cost of fuel per KWH generated and a 15.5% decrease in the volume of KWHs generated by coal.

Purchased Power – Non-Affiliates

In the first quarter 2016, purchased power expense from non-affiliates was $83 million compared to $60 million in the corresponding period in 2015. The increase was primarily due to a 75.3% increase in the volume of KWHs purchased, partially offset by a 28.1% decrease in the average cost per KWH purchased primarily resulting from lower natural gas prices.

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

Purchased Power – Affiliates

In the first quarter 2016, purchased power expense from affiliates was $139 million compared to $149 million in the corresponding period in 2015. The decrease was the result of an 8.8% decrease in the volume of KWHs purchased in the first quarter 2016 as Georgia Power's units generally dispatched at a lower cost than other Southern Company system resources.

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.

58

GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Other Operations and Maintenance Expenses

First Quarter 2016 vs. First Quarter 2015
(change in millions)	(% change)
$(17)	(3.6)

In the first quarter 2016, other operations and maintenance expenses were $457 million compared to $474 million in the corresponding period in 2015. The decrease was primarily due to decreases of $17 million in scheduled outage and maintenance costs at generation facilities and $7 million in employee benefits including pension costs, partially offset by an increase of $3 million for integrated transmission system billings. See Note (F) to the Condensed Financial Statements herein for additional information related to pension costs.

Income Taxes

First Quarter 2016 vs. First Quarter 2015
(change in millions)	(% change)
$20	14.3

In the first quarter 2016, income taxes were $160 million compared to $140 million in the corresponding period in 2015. The increase was primarily due to higher pre-tax earnings.

FUTURE EARNINGS POTENTIAL

The results of operations discussed above are not necessarily indicative of Georgia Power's future earnings potential. The level of Georgia Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Georgia Power's business of selling electricity. These factors include Georgia Power's ability to maintain a constructive regulatory environment that continues to allow for the timely recovery of prudently-incurred costs during a time of increasing costs and the completion and subsequent operation of ongoing construction projects, primarily Plant Vogtle Units 3 and 4. Future earnings in the near term will depend, in part, upon maintaining and growing sales which are subject to a number of factors. These factors include weather, competition, new energy contracts with other utilities, energy conservation practiced by customers, the use of alternative energy sources by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in Georgia Power's service territory. Demand for electricity is primarily driven by economic growth. The pace of economic growth and electricity demand may be affected by changes in regional and global economic conditions, which 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 (ECCR) tariff allows for the recovery of capital and operations and maintenance costs related to environmental controls mandated by state and federal regulations. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified, as compliance plans are revised or updated, and as legal challenges to rules are completed. 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.

59

GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Environmental Statutes and Regulations

Air Quality

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Air Quality" of Georgia Power in Item 7 of the Form 10-K for additional information regarding the EPA's final MATS rule and regional haze regulations.

On April 25, 2016, in response to a June 2015 U.S. Supreme Court opinion, the EPA published its supplemental finding regarding consideration of costs in support of the MATS rule. This finding does not impact MATS rule compliance requirements, costs, or deadlines, and all Georgia Power units that are subject to the MATS rule have completed the measures necessary to achieve compliance with the MATS rule by the applicable deadlines.

Also on April 25, 2016, the EPA issued proposed revisions to the regional haze regulations. The ultimate impact of the proposed revisions will depend on their ultimate adoption, implementation, and any legal challenges and cannot be determined at this time.

Retail Regulatory Matters

Georgia Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Georgia PSC. Georgia Power currently recovers its costs from the regulated retail business through the 2013 ARP, which includes traditional base tariff rates, Demand-Side Management tariffs, ECCR tariffs, and Municipal Franchise Fee tariffs. In addition, financing costs related to the construction of Plant Vogtle Units 3 and 4 are being collected through the NCCR tariff and fuel costs are collected through separate fuel cost recovery tariffs. See "Fuel Cost Recovery" below and Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding fuel cost recovery and the NCCR tariff, respectively.

Pursuant to the terms and conditions of a settlement agreement related to Southern Company's proposed acquisition of AGL Resources approved by the Georgia PSC on April 14, 2016, Georgia Power's 2013 ARP will continue in effect until December 31, 2019, and Georgia Power will be required to file its next base rate case by July 1, 2019. Furthermore, through December 31, 2019, Georgia Power and Atlanta Gas Light Company (collectively, Utilities) will retain the merger savings, net of transition costs, as defined in the settlement agreement; through December 31, 2022, net merger savings will be shared on a 60/40 basis between customers and the Utilities; thereafter, all merger savings will be retained by customers. See Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information regarding the 2013 ARP.

Renewables

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Renewables" of Georgia Power in Item 7 of the Form 10-K for information regarding renewable energy projects.

As part of the Georgia Power Advanced Solar Initiative, four PPAs totaling 149 MWs of solar contracted capacity from Southern Power began in the first quarter 2016.

Fuel Cost Recovery

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Fuel Cost Recovery" of Georgia Power in Item 7 of the Form 10-K for information regarding fuel cost recovery.

Georgia Power has established fuel cost recovery rates approved by the Georgia PSC. On April 14, 2016, Georgia Power filed a request with the Georgia PSC to decrease fuel rates by 15% effective June 1, 2016, which is expected to reduce annual billings by approximately $313 million. Georgia Power is currently scheduled to file its next fuel case by February 28, 2017. The ultimate outcome of this matter cannot be determined at this time.

60

GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Nuclear Construction

See Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding the construction of Plant Vogtle Units 3 and 4, Vogtle Construction Monitoring (VCM) reports, the NCCR tariff, the Vogtle Construction Litigation (as defined below), and the Contractor Settlement Agreement (as defined below).

In 2008, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into an agreement with 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).

Under the terms of the Vogtle 3 and 4 Agreement, the Vogtle Owners agreed to pay a purchase price that is subject to certain price escalations and adjustments, including fixed escalation amounts and index-based adjustments, as well as adjustments for change orders, and performance bonuses for early completion and unit performance. The Vogtle 3 and 4 Agreement also provides for liquidated damages upon the Contractor's failure to fulfill the schedule and performance guarantees, subject to a cap. In addition, the Vogtle 3 and 4 Agreement provides for limited cost sharing by the Vogtle Owners for Contractor costs under certain conditions (which have not occurred), with maximum additional capital costs under this provision attributable to Georgia Power (based on Georgia Power's ownership interest) of approximately $114 million. Each Vogtle Owner is severally (and not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to the Contractor under the Vogtle 3 and 4 Agreement. Georgia Power's proportionate share is 45.7%.

On December 31, 2015, Westinghouse acquired Stone & Webster, Inc. from Chicago Bridge & Iron Company, N.V. (CB&I) and changed the name of Stone & Webster, Inc. to WECTEC Global Project Services Inc. (WECTEC). Certain obligations of Westinghouse and WECTEC under the Vogtle 3 and 4 Agreement were originally guaranteed by Toshiba Corporation (Westinghouse's parent company) and The Shaw Group Inc. (which is now a subsidiary of CB&I), respectively. On March 9, 2016, in connection with Westinghouse's acquisition of WECTEC and pursuant to the settlement agreement described below, the guarantee of The Shaw Group Inc. was terminated. The guarantee of Toshiba Corporation remains in place. 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. Additionally, as a result of credit rating downgrades of Toshiba Corporation, Westinghouse provided the Vogtle Owners with letters of credit in an aggregate amount of $920 million in accordance with, and subject to adjustment under, the terms of the Vogtle 3 and 4 Agreement.

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 Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4. 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 construction capital costs to be borne by Georgia Power increase by 5% above the certified cost 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. In February 2013, Georgia Power 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 (from April 2016) and the fourth quarter 2018 (from April 2017) for Plant Vogtle Units 3 and 4, respectively. In October 2013, the Georgia PSC approved a stipulation (2013 Stipulation) between Georgia Power and the Georgia PSC Staff (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.

On April 15, 2015, the Georgia PSC issued a procedural order in connection with the twelfth VCM report, which included a requested amendment (Requested Amendment) to the Plant Vogtle Units 3 and 4 certificate to reflect the

61

GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Contractor's revised forecast for completion of Plant Vogtle Units 3 and 4 (second quarter of 2019 and second quarter of 2020, respectively) as well as additional estimated Vogtle Owner's costs, of approximately $10 million per month, including property taxes, oversight costs, compliance costs, and other operational readiness costs to include the estimated Vogtle Owner's costs associated with the proposed 18-month Contractor delay and to increase the estimated total in-service capital cost of Plant Vogtle Units 3 and 4 to $5.0 billion. Pursuant to the Georgia PSC's procedural order, the Georgia PSC deemed the Requested Amendment unnecessary and withdrawn until the completion of construction of Plant Vogtle Unit 3 consistent with the 2013 Stipulation. The Georgia PSC recognized that the certified cost and the 2013 Stipulation do not constitute a cost recovery cap. In accordance with the Georgia Integrated Resource Planning Act, any costs incurred by Georgia Power in excess of the certified amount will be included in rate base, provided Georgia Power shows the costs to be reasonable and prudent. Financing costs up to the certified amount will be collected through the NCCR tariff until the units are placed in service and contemplated in a general base rate case, while financing costs on any construction-related costs in excess of the $4.4 billion certified amount are expected to be recovered through AFUDC.

On December 31, 2015, Westinghouse and the Vogtle Owners entered into a definitive settlement agreement (Contractor Settlement Agreement) to resolve disputes between the Vogtle Owners and the Contractor under the Vogtle 3 and 4 Agreement, including litigation that was pending in the U.S. District Court for the Southern District of Georgia (Vogtle Construction Litigation). Effective December 31, 2015, Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the Contractor entered into an amendment to the Vogtle 3 and 4 Agreement to implement the Contractor Settlement Agreement. The Contractor Settlement Agreement and the related amendment to the Vogtle 3 and 4 Agreement (i) restrict the Contractor's ability to seek further increases in the contract price by clarifying and limiting the circumstances that constitute nuclear regulatory changes in law; (ii) provide for enhanced dispute resolution procedures; (iii) revise the guaranteed substantial completion dates to match the current estimated in-service dates of June 30, 2019 for Unit 3 and June 30, 2020 for Unit 4; (iv) provide that delay liquidated damages will commence from the current estimated nuclear fuel loading date for each unit, which is December 31, 2018 for Unit 3 and December 31, 2019 for Unit 4; and (v) provide that Georgia Power, based on its ownership interest, will pay to the Contractor and capitalize to the project cost approximately $350 million, of which approximately $241 million had been paid as of March 31, 2016. In addition, the Contractor Settlement Agreement provides for the resolution of other open existing items relating to the scope of the project under the Vogtle 3 and 4 Agreement, including cyber security, for which costs were reflected in Georgia Power's previously disclosed in-service cost estimate. Further, as part of the settlement and Westinghouse's acquisition of WECTEC: (i) Westinghouse engaged Fluor Enterprises, Inc., a subsidiary of Fluor Corporation, as a new construction subcontractor; and (ii) the Vogtle Owners, CB&I, and The Shaw Group Inc. entered into mutual releases of any and all claims arising out of events or circumstances in connection with the construction of Plant Vogtle Units 3 and 4 that occurred on or before the date of the Contractor Settlement Agreement. On January 5, 2016, the Vogtle Construction Litigation was dismissed with prejudice.

On January 21, 2016, Georgia Power submitted the Contractor Settlement Agreement and the related amendment to the Vogtle 3 and 4 Agreement to the Georgia PSC for its review. In accordance with the Georgia PSC's subsequent order, on April 5, 2016, Georgia Power filed supplemental information in support of the Contractor Settlement Agreement and Georgia Power's position that all construction costs to date have been prudently incurred and that the current estimated in-service capital cost and schedule are reasonable. The Staff will conduct a review of all costs incurred related to Plant Vogtle Units 3 and 4, the schedule for completion of Plant Vogtle Units 3 and 4, and the Contractor Settlement Agreement and the Staff is authorized to engage in related settlement discussions with Georgia Power and any intervenors.

The order provides that the Staff is required to report to the Georgia PSC by October 19, 2016 with respect to the status of its review and any settlement-related negotiations. If a settlement with the Staff is reached with respect to costs of Plant Vogtle Units 3 and 4, the Georgia PSC will then conduct a hearing to consider whether to approve that settlement. If a settlement with the Staff is not reached, the Georgia PSC will determine how to proceed, including (i) modifying the 2013 Stipulation, (ii) directing Georgia Power to file a request for an amendment to the certificate

62

GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

for Plant Vogtle Units 3 and 4, (iii) issuing a scheduling order to address remaining disputed issues, or (iv) taking any other option within its authority.

The Georgia PSC has approved thirteen VCM reports covering the periods through June 30, 2015, including construction capital costs incurred, which through that date totaled $3.1 billion. On February 26, 2016, Georgia Power filed its fourteenth VCM report with the Georgia PSC covering the period from July 1 through December 31, 2015. The fourteenth VCM report does not include a requested amendment to the certified cost of Plant Vogtle Units 3 and 4. Georgia Power is requesting approval of $160 million of construction capital costs incurred during that period. Georgia Power anticipates to incur average financing costs of approximately $27 million per month from January 2016 until Plant Vogtle Units 3 and 4 are placed in service. The updated in-service capital cost forecast is $5.44 billion and includes costs related to the Contractor Settlement Agreement. Estimated financing costs during the construction period total approximately $2.4 billion. Georgia Power's CWIP balance for Plant Vogtle Units 3 and 4 was approximately $3.7 billion as of March 31, 2016.

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 may arise as construction proceeds. Processes are in place that are designed to assure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating licenses, 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 may 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 challenges with Contractor performance including fabrication, assembly, delivery, and installation of the shield building and structural modules, delays in the receipt of the remaining permits necessary for the operation of Plant Vogtle Units 3 and 4, or other issues could arise and may further impact project schedule and cost. In addition, the IRS allocated production tax credits to each of Plant Vogtle Units 3 and 4, which require the applicable unit to be placed in service before 2021.

Future claims by the Contractor or Georgia Power (on behalf of the Vogtle Owners) could arise throughout construction. These claims may be resolved through formal and informal dispute resolution procedures under the Vogtle 3 and 4 Agreement and, under the enhanced dispute resolution procedures, may be resolved through litigation after the completion of nuclear fuel load for both units.

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

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

Other Matters

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

The ultimate outcome of such pending or potential litigation against Georgia Power cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements herein

63

GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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

Recently Issued Accounting Standards

On February 25, 2016, the FASB issued ASU No. 2016-02, Leases(Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. Georgia Power is currently evaluating the new standard and has not yet determined its ultimate impact; however, adoption of ASU 2016-02 is expected to have a significant impact on Georgia Power's balance sheet.

On March 30, 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation(Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions. Most significantly, entities are required to recognize all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation as income tax expense or benefit in the income statement. Georgia Power currently recognizes any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation in additional paid-in capital. ASU 2016-09 is effective for fiscal years beginning after December 15, 2016, with early adoption permitted. Georgia Power is currently evaluating the new standard and has not yet determined its ultimate impact.

FINANCIAL CONDITION AND LIQUIDITY

Overview

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Georgia Power in Item 7 of the Form 10-K for additional information. Georgia Power's financial condition remained stable at March 31, 2016. Georgia Power intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit agreements to meet future capital and liquidity needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.

Net cash provided from operating activities totaled $563 million for the first three months of 2016 compared to $363 million for the corresponding period in 2015. The increase was primarily due to the timing of vendor payments. Net cash used for investing activities totaled $689 million for the first three months of 2016 compared to

64

GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

$405 million for the corresponding period in 2015 primarily related to installation of equipment to comply with environmental standards and construction of generation, transmission, and distribution facilities. Net cash provided from financing activities totaled $119 million for the first three months of 2016 compared to $431 million in the corresponding period in 2015. The decrease in cash provided from financing activities is primarily due to a maturity of senior notes and a reduction in short-term debt, partially offset by senior note issuances and an increase in capital contributions received from Southern Company. Fluctuations in cash flow from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes for the first three months of 2016 include an increase in long-term debt of $398 million primarily related to issuances of senior notes, an increase of $374 million in property, plant, and equipment to comply with environmental standards and construction of generation, transmission, and distribution facilities, and an increase of $229 million in paid-in capital primarily due to capital contributions received from Southern Company.

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 $458 million will be required through March 31, 2017 to fund maturities of long-term debt. See "Sources of Capital" herein for additional information.

The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental statutes and regulations; the outcome of any legal challenges to 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, external security issuances, term loans, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon regulatory approval, prevailing market conditions, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Georgia Power in Item 7 of the Form 10-K for additional information.

In addition, Georgia Power may make borrowings through a loan guarantee agreement (Loan Guarantee Agreement) between Georgia Power and the DOE, the proceeds of which may be used to reimburse Georgia Power for Eligible Project Costs incurred in connection with its construction of Plant Vogtle Units 3 and 4. Under the Loan Guarantee Agreement, the DOE agreed to guarantee borrowings of up to $3.46 billion (not to exceed 70% of Eligible Project Costs) to be made by Georgia Power under a multi-advance credit facility (FFB Credit Facility) among Georgia Power, the DOE, and the FFB. Eligible Project Costs incurred through March 31, 2016 would allow for borrowings

65

GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

of up to $2.5 billion under the FFB Credit Facility, of which Georgia Power has borrowed $2.2 billion. See Note 6 to the financial statements of Georgia Power under "DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K for additional information regarding the Loan Guarantee Agreement and Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" herein for additional information regarding Plant Vogtle Units 3 and 4.

As of March 31, 2016, Georgia Power's current liabilities exceeded current assets by $262 million primarily due to long-term debt due within one year. Georgia Power intends to utilize operating cash flows, as well as FFB borrowings, commercial paper, lines of credit, bank notes, and external securities issuances, as market conditions permit, and equity contributions from Southern Company to fund its short-term capital needs. Georgia Power has substantial cash flow from operating activities and access to the capital markets and financial institutions to meet liquidity needs.

At March 31, 2016, Georgia Power had approximately $60 million of cash and cash equivalents. Georgia Power's committed credit arrangement with banks at March 31, 2016 was $1.75 billion of which $1.73 billion was unused. This credit arrangement expires in 2020.

This bank credit arrangement contains a covenant that limits debt levels and contains a cross acceleration provision to other indebtedness (including guarantee obligations) of Georgia Power. Such cross acceleration provision to other indebtedness would trigger an event of default if Georgia Power defaulted on indebtedness, the payment of which was then accelerated. Georgia Power is currently in compliance with this covenant. This bank credit arrangement does not contain a material adverse change clause at the time of borrowing.

Subject to applicable market conditions, Georgia Power expects to renew or replace this credit arrangement, as needed, prior to expiration. In connection therewith, Georgia Power may extend the maturity date and/or increase or decrease the lending commitments thereunder.

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 pollution control revenue bonds and commercial paper program. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of March 31, 2016 was approximately $868 million. In addition, at March 31, 2016, Georgia Power had $69 million of fixed rate pollution control revenue bonds outstanding that were required to be reoffered within the next 12 months.

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 During the Period(*)
	Average Amount Outstanding		Weighted Average Interest Rate		Maximum Amount Outstanding
	(in millions)				(in millions)
Commercial paper	$	29	0.7	%	$	158

(*) Average and maximum amounts are based upon daily balances during the three-month period ended March 31, 2016. No short-term debt was outstanding at March 31, 2016.

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

66

GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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, transmission, and construction of new generation at Plant Vogtle Units 3 and 4.

The maximum potential collateral requirements under these contracts at March 31, 2016 were as follows:

Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB- and/or Baa3	$	93
Below BBB- and/or Baa3	$	1,247

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, a credit rating downgrade could impact the ability of Georgia Power to access capital markets and would be likely to impact the cost at which it does so.

Financing Activities

In January 2016, $4.085 million aggregate principal amount of Savannah Economic Development Authority Pollution Control Revenue Bonds (Savannah Electric and Power Company Project), First Series 1993 matured.

In March 2016, Georgia Power issued $325 million aggregate principal amount of Series 2016A 3.25% Senior Notes due April 1, 2026 and $325 million aggregate principal amount of Series 2016B 2.40% Senior Notes due April 1, 2021. An amount equal to the proceeds from the Series 2016A 3.25% Senior Notes due April 1, 2026 will be allocated to eligible green expenditures, including financing of or investments in solar power generation facilities or electric vehicle charging infrastructure, or payments under PPAs served by solar power or wind generation facilities. The proceeds from the Series 2016B 2.40% Senior Notes due April 1, 2021 were used to repay at maturity $250 million aggregate principal amount of Georgia Power's Series 2013B Floating Rate Senior Notes due March 15, 2016, to repay a portion of Georgia Power's short-term indebtedness, and for general corporate purposes, including Georgia Power's continuous construction program.

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.

67

GULF POWER COMPANY

68

GULF POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended March 31,
	2016			2015
	(in millions)
Operating Revenues:
Retail revenues	$	283		$	293
Wholesale revenues, non-affiliates	16			25
Wholesale revenues, affiliates	21			22
Other revenues	15			17
Total operating revenues	335			357
Operating Expenses:
Fuel	94			110
Purchased power, non-affiliates	30			25
Purchased power, affiliates	2			9
Other operations and maintenance	77			93
Depreciation and amortization	38			20
Taxes other than income taxes	29			28
Total operating expenses	270			285
Operating Income	65			72
Other Income and (Expense):
Allowance for equity funds used during construction	—			4
Interest expense, net of amounts capitalized	(13		)	(13		)
Other income (expense), net	(1		)	(1		)
Total other income and (expense)	(14		)	(10		)
Earnings Before Income Taxes	51			62
Income taxes	20			23
Net Income	31			39
Dividends on Preference Stock	2			2
Net Income After Dividends on Preference Stock	$	29		$	37

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended March 31,
	2016			2015
	(in millions)
Net Income	$	31		$	39
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(2) and $-, respectively	(3		)	—
Total other comprehensive income (loss)	(3		)	—
Comprehensive Income	$	28		$	39

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

69

GULF POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Three Months Ended March 31,
	2016			2015
	(in millions)
Operating Activities:
Net income	$	31		$	39
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	40			22
Deferred income taxes	9			27
Allowance for equity funds used during construction	—			(4		)
Other, net	(2		)	11
Changes in certain current assets and liabilities —
-Receivables	35			12
-Fossil fuel stock	15			(2		)
-Other current assets	2			5
-Accounts payable	(6		)	(28		)
-Accrued taxes	13			5
-Accrued compensation	(18		)	(16		)
-Other current liabilities	13			10
Net cash provided from operating activities	132			81
Investing Activities:
Property additions	(32		)	(84		)
Cost of removal, net of salvage	(2		)	(5		)
Change in construction payables	(6		)	(1		)
Other investing activities	(2		)	(2		)
Net cash used for investing activities	(42		)	(92		)
Financing Activities:
Increase (decrease) in notes payable, net	(85		)	40
Proceeds — Common stock issued to parent	—			20
Payment of common stock dividends	(30		)	(33		)
Other financing activities	(1		)	—
Net cash provided from (used for) financing activities	(116		)	27
Net Change in Cash and Cash Equivalents	(26		)	16
Cash and Cash Equivalents at Beginning of Period	74			39
Cash and Cash Equivalents at End of Period	$	48		$	55
Supplemental Cash Flow Information:
Cash paid (received) during the period for --
Interest (net of $- and $2 capitalized for 2016 and 2015, respectively)	$	3		$	3
Income taxes, net	(25		)	(8		)
Noncash transactions — Accrued property additions at end of period	15			41

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

70

GULF POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Assets	At March 31, 2016			At December 31, 2015
	(in millions)
Current Assets:
Cash and cash equivalents	$	48		$	74
Receivables —
Customer accounts receivable	64			76
Unbilled revenues	52			54
Under recovered regulatory clause revenues	21			20
Income taxes receivable, current	—			27
Other accounts and notes receivable	5			9
Affiliated companies	8			1
Accumulated provision for uncollectible accounts	(1		)	(1		)
Fossil fuel stock, at average cost	93			108
Materials and supplies, at average cost	58			56
Other regulatory assets, current	90			90
Other current assets	18			22
Total current assets	456			536
Property, Plant, and Equipment:
In service	5,058			5,045
Less accumulated provision for depreciation	1,324			1,296
Plant in service, net of depreciation	3,734			3,749
Other utility plant, net	60			62
Construction work in progress	57			48
Total property, plant, and equipment	3,851			3,859
Other Property and Investments	4			4
Deferred Charges and Other Assets:
Deferred charges related to income taxes	60			61
Other regulatory assets, deferred	420			427
Other deferred charges and assets	37			33
Total deferred charges and other assets	517			521
Total Assets	$	4,828		$	4,920

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

71

GULF POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholder's Equity	At March 31, 2016			At December 31, 2015
	(in millions)
Current Liabilities:
Securities due within one year	$	110		$	110
Notes payable	56			142
Accounts payable —
Affiliated	46			55
Other	42			44
Customer deposits	36			36
Accrued taxes —
Accrued income taxes	10			4
Other accrued taxes	16			9
Accrued interest	20			9
Accrued compensation	8			25
Deferred capacity expense, current	22			22
Other regulatory liabilities, current	22			22
Liabilities from risk management activities	54			49
Other current liabilities	38			40
Total current liabilities	480			567
Long-term Debt	1,193			1,193
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	899			893
Employee benefit obligations	128			129
Deferred capacity expense	136			141
Asset retirement obligations	114			113
Other cost of removal obligations	233			233
Other regulatory liabilities, deferred	45			47
Other deferred credits and liabilities	100			102
Total deferred credits and other liabilities	1,655			1,658
Total Liabilities	3,328			3,418
Preference Stock	147			147
Common Stockholder's Equity:
Common stock, without par value —
Authorized - 20,000,000 shares
Outstanding - March 31, 2016: 5,642,717 shares
- December 31, 2015: 5,642,717 shares	503			503
Paid-in capital	569			567
Retained earnings	284			285
Accumulated other comprehensive loss	(3		)	—
Total common stockholder's equity	1,353			1,355
Total Liabilities and Stockholder's Equity	$	4,828		$	4,920

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

72

GULF POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

FIRST QUARTER 2016 vs. FIRST QUARTER 2015

OVERVIEW

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

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

Through 2015, capacity revenues from long-term non-affiliate sales out of Gulf Power's ownership of Plant Scherer Unit 3 (205 MWs) represented the majority of Gulf Power's wholesale earnings. The capacity revenues associated with these contracts covering 100% of Gulf Power's ownership represented 82% of wholesale capacity revenues in 2015. Due to the expiration of a wholesale contract at the end of 2015 and another wholesale contract at the end of May 2016, Gulf Power's remaining contracted sales from the unit from June 2016 through 2019 will cover approximately 24% of the unit. The expiration of the contract in 2015 and the scheduled future expiration of the remaining contracts will have a material negative impact on Gulf Power's earnings in 2016 and may continue to have a material negative impact in future years until Gulf Power is able to find a suitable alternative related to this asset. The alternatives Gulf Power is actively evaluating include, without limitation, rededication of the asset to serve retail customers for whom it was originally planned and built, replacement long-term wholesale contracts or other sales into the wholesale market, or an asset sale. On May 5, 2016, Gulf Power delivered a letter to the Florida PSC requesting recognition of Gulf Power's ownership in Plant Scherer Unit 3 as being in service to retail customers when and as the contracts expire. The ultimate outcome of this matter cannot be determined at this time.

In 2013, the Florida PSC voted to approve the settlement agreement (Rate Case Settlement Agreement) among Gulf Power and all of the intervenors to Gulf Power's retail base rate case. Under the terms of the Rate Case Settlement Agreement, Gulf Power (1) increased base rates approximately $35 million annually effective January 2014 and subsequently increased base rates approximately $20 million annually effective January 2015; (2) continued its current authorized retail ROE midpoint (10.25%) and range (9.25% – 11.25%); (3) may reduce depreciation and record a regulatory asset that will be included as an offset to the other cost of removal regulatory liability in an aggregate amount up to $62.5 million between January 2014 and June 2017, of which $34.1 million had been recorded as of March 31, 2016; and (4) is accruing a return similar to AFUDC on certain transmission system upgrades placed into service after January 2014 until the next base rate adjustment date or January 1, 2017, whichever comes first. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Retail Base Rate Case" herein for additional details of the Rate Case Settlement Agreement.

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.

73

GULF POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

Net Income

First Quarter 2016 vs. First Quarter 2015
(change in millions)	(% change)
$(8)	(21.6)

Gulf Power's net income after dividends on preference stock for the first quarter 2016 was $29 million compared to $37 million for the corresponding period in 2015. The decrease was primarily due to an increase in depreciation and a decrease in non-affiliated wholesale capacity revenues, partially offset by lower operations and maintenance expenses.

Retail Revenues

First Quarter 2016 vs. First Quarter 2015
(change in millions)	(% change)
$(10)	(3.4)

In the first quarter 2016, retail revenues were $283 million compared to $293 million for the corresponding period in 2015.

Details of the changes in retail revenues were as follows:

	First Quarter 2016
	(in millions)			(% change)
Retail – prior year	$	293
Estimated change resulting from –
Rates and pricing	7			2.4
Sales growth	2			0.7
Weather	(4		)	(1.4	)
Fuel and other cost recovery	(15		)	(5.1	)
Retail – current year	$	283		(3.4	)%

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

Revenues associated with changes in rates and pricing increased in the first quarter 2016 when compared to the corresponding period in 2015 primarily due to an increase in the environmental cost recovery clause rate, partially offset by a decrease in the energy conservation cost recovery clause rate, both effective in January 2016.

Revenues attributable to changes in sales increased in the first quarter 2016 when compared to the corresponding period in 2015. For the first quarter 2016, weather-adjusted KWH energy sales to residential customers increased 2.8% due to customer growth and higher customer usage. Weather-adjusted KWH energy sales to commercial customers increased 0.1% due to customer growth, mostly offset by lower customer usage. KWH energy sales to industrial customers increased 7.1% for the first quarter 2016 primarily due to decreased customer co-generation, partially offset by changes in customers' operations.

74

GULF POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Fuel and other cost recovery revenues decreased in the first quarter 2016 when compared to the corresponding period in 2015 primarily due to a decrease in the fuel cost recovery rate effective in January 2016 and a decrease in fuel costs as the result of decreased generation and lower purchased power energy costs.

Fuel and other cost recovery provisions include fuel expenses, the energy component of purchased power costs, purchased power capacity costs, and the difference between projected and actual costs and revenues related to energy conservation and environmental compliance. See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses – Retail Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information.

Wholesale Revenues – Non-Affiliates

First Quarter 2016 vs. First Quarter 2015
(change in millions)	(% change)
$(9)	(36.0)

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

In the first quarter 2016, wholesale revenues from sales to non-affiliates were $16 million compared to $25 million for the corresponding period in 2015. The decrease was primarily due to a 42.2% decrease in capacity revenues resulting from the expiration of a Plant Scherer Unit 3 sales agreement and a 23.9% decrease in KWH sales resulting from lower sales under the remaining Plant Scherer Unit 3 long-term sales agreements due to lower natural gas prices.

Fuel and Purchased Power Expenses

	First Quarter 2016 vs. First Quarter 2015
	(change in millions)			(% change)
Fuel	$	(16	)	(14.5	)
Purchased power – non-affiliates	5			20.0
Purchased power – affiliates	(7		)	(77.8	)
Total fuel and purchased power expenses	$	(18	)

In the first quarter 2016, total fuel and purchased power expenses were $126 million compared to $144 million for the corresponding period in 2015. The decrease was primarily the result of a $23 million decrease due to the lower average cost of fuel and purchased power as a result of lower generation from Gulf Power's coal-fired resources, partially offset by a $5 million increase related to the volume of KWHs generated due to higher generation from Gulf Power's gas-fired resources.

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 and purchased power capacity cost recovery clauses and long-term wholesale contracts. See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses – Retail Fuel Cost Recovery" and " – Purchased Power Capacity Recovery" in Item 8 of the Form 10-K for additional information.

75

GULF POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

	First Quarter 2016	First Quarter 2015
Total generation (millions of KWHs)	1,816	2,236
Total purchased power (millions of KWHs)	1,760	1,259
Sources of generation (percent) –
Coal	42	59
Gas	58	41
Cost of fuel, generated (cents per net KWH) –
Coal	3.92	3.98
Gas	3.75	3.95
Average cost of fuel, generated (cents per net KWH)	3.82	3.97
Average cost of purchased power (cents per net KWH)(*)	3.22	4.36

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

Fuel

In the first quarter 2016, fuel expense was $94 million compared to $110 million for the corresponding period in 2015. The decrease was primarily due to a 41.1% decrease in the volume of KWHs generated by Gulf Power's coal-fired generation resources and a 3.8% decrease in the average cost of fuel, partially offset by a 12.7% increase in the volume of KWHs generated by Gulf Power's gas-fired generation resources.

Purchased Power – Non-Affiliates

In the first quarter 2016, purchased power expense from non-affiliates was $30 million compared to $25 million for the corresponding period in 2015. The increase was primarily due to a 73.8% increase in the volume of KWHs purchased due to the availability of lower cost energy, partially offset by a 32.2% decrease in the average cost per KWH purchased due to lower energy costs from gas-fired market resources.

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

Purchased Power – Affiliates

In the first quarter 2016, purchased power expense from affiliates was $2 million compared to $9 million for the corresponding period in 2015. The decrease was primarily due to a 62.4% decrease in the volume of KWHs purchased due to lower territorial loads resulting from milder weather and a 39.4% decrease in the average cost per KWH purchased due to lower power pool interchange rates as a result of lower natural gas prices and lower off-peak energy prices of renewable market resources.

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.

76

GULF POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Other Operations and Maintenance Expenses

First Quarter 2016 vs. First Quarter 2015
(change in millions)	(% change)
$(16)	(17.2)

In the first quarter 2016, other operations and maintenance expenses were $77 million compared to $93 million for the corresponding period in 2015. The decrease was primarily due to a decrease of $11 million in scheduled generation outage expenses.

Depreciation and Amortization

First Quarter 2016 vs. First Quarter 2015
(change in millions)	(% change)
$18	90.0

In the first quarter 2016, depreciation and amortization was $38 million compared to $20 million for the corresponding period in 2015. The increase was primarily due to $14 million less of a reduction in depreciation in the first three months of 2016 compared to the corresponding period in 2015, as authorized in the Rate Case Settlement Agreement, and property additions at generation, transmission, and distribution facilities.

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 and Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Gulf Power – Retail Base Rate Case" herein for additional information.

Allowance for Equity Funds Used During Construction

First Quarter 2016 vs. First Quarter 2015
(change in millions)	(% change)
$(4)	(100.0)

In the first quarter 2016, AFUDC equity was immaterial compared to $4 million for the corresponding period in 2015. The decrease was primarily due to environmental control projects at generation facilities and transmission projects being placed in service in 2015.

FUTURE EARNINGS POTENTIAL

The results of operations discussed above are not necessarily indicative of Gulf Power's future earnings potential. The level of Gulf Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Gulf Power's business of selling electricity. These factors include Gulf Power's ability to maintain a constructive regulatory environment that continues to allow for the timely recovery of prudently-incurred costs during a time of increasing costs. Future earnings in the near term will depend, in part, upon maintaining and growing sales which are subject to a number of factors. These factors include weather, competition, energy conservation practiced by customers, the use of alternative energy sources by customers, the price of electricity, the price elasticity of demand, the rate of economic growth or decline in Gulf Power's service territory, and the successful remarketing of wholesale capacity as current contracts expire. Demand for electricity is primarily driven by economic growth. The pace of economic growth and electricity demand may be affected by changes in regional and global economic conditions, which may impact future earnings. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Gulf Power in Item 7 of the Form 10-K.

Gulf Power's wholesale business consists of two types of agreements. The first type, referred to as requirements service, provides that Gulf Power serves the customer's capacity and energy requirements from Gulf Power resources. The second type, referred to as a unit sale, is a wholesale customer purchase from a dedicated generating

77

GULF POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

plant unit where a portion of that unit is reserved for the customer. These agreements are associated with Gulf Power's ownership of Plant Scherer Unit 3 (205 MWs) and consist of both capacity and energy sales. Through 2015, capacity revenues from long-term non-affiliate sales out of Gulf Power's ownership of the unit represented the majority of Gulf Power's wholesale earnings. The capacity revenues associated with these contracts covering 100% of Gulf Power's ownership represented 82% of wholesale capacity revenues in 2015. Due to the expiration of a wholesale contract at the end of 2015 and another wholesale contract at the end of May 2016, Gulf Power's remaining contracted sales from the unit from June 2016 through 2019 will cover approximately 24% of the unit. The expiration of the contract in 2015 and the scheduled future expiration of the remaining contracts will have a material negative impact on Gulf Power's earnings in 2016 and may continue to have a material negative impact in future years until Gulf Power is able to find a suitable alternative related to this asset. The alternatives Gulf Power is actively evaluating include, without limitation, rededication of the asset to serve retail customers for whom it was originally planned and built, replacement long-term wholesale contracts or other sales into the wholesale market, or an asset sale. On May 5, 2016, Gulf Power delivered a letter to the Florida PSC requesting recognition of Gulf Power's ownership in Plant Scherer Unit 3 as being in service to retail customers when and as the contracts expire. The ultimate outcome of this matter cannot be determined at this time.

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 retail rates or through long-term wholesale agreements on a timely basis or through market-based contracts. The State of Florida has statutory provisions that allow a utility to petition the Florida PSC for recovery of prudent environmental compliance costs that are not being recovered through base rates or any other recovery mechanism. Gulf Power's current long-term wholesale agreements contain provisions that permit charging the customer with costs incurred as a result of changes in environmental laws and regulations. The full impact of any such regulatory or legislative changes cannot be determined at this time. Environmental compliance spending over the next several years may differ materially from the amounts estimated. The timing, specific requirements, and estimated costs could change as environmental statutes and regulations are adopted or modified, as compliance plans are revised or updated, and as legal challenges to rules are completed. 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," "Retail Regulatory Matters – Cost Recovery Clauses – Environmental Cost Recovery," and "Other Matters" 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 EPA's final MATS rule and regional haze regulations.

On April 25, 2016, in response to a June 2015 U.S. Supreme Court opinion, the EPA published its supplemental finding regarding consideration of costs in support of the MATS rule. This finding does not impact MATS rule compliance requirements, costs, or deadlines, and all Gulf Power units that are subject to the MATS rule have completed the measures necessary to achieve compliance with the MATS rule by the applicable deadlines.

Also on April 25, 2016, the EPA issued proposed revisions to the regional haze regulations. The ultimate impact of the proposed revisions will depend on their ultimate adoption, implementation, and any legal challenges and cannot be determined at this time.

78

GULF POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Retail Regulatory Matters

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

Retail Base Rate Case

In 2013, the Florida PSC approved the Rate Case Settlement Agreement providing that Gulf Power may reduce depreciation and record a regulatory asset up to $62.5 million between January 2014 and June 2017. In any given month, such depreciation reduction may not exceed the amount necessary for the retail ROE, as reported to the Florida PSC monthly, to reach the midpoint of the authorized retail ROE range then in effect. For 2014, 2015, and the first three months of 2016, Gulf Power recognized reductions in depreciation of $8.4 million, $20.1 million, and $5.6 million, respectively.

Cost Recovery Clauses

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

Renewables

The Florida PSC issued a final approval order on Gulf Power's Community Solar Pilot Program on April 15, 2016. The program will offer all Gulf Power customers an opportunity to voluntarily contribute to the construction and operation of a solar photovoltaic facility with electric generating capacity of up to 1 MW through annual subscriptions. The energy generated from the solar facility is expected to provide power to all of Gulf Power's customers.

Other Matters

As a result of the cost to comply with environmental regulations imposed by the EPA, Gulf Power retired its coal-fired generation at Plant Smith Units 1 and 2 (357 MWs) on March 31, 2016. In connection with this retirement announcement, Gulf Power reclassified the net carrying value of these units from plant in service, net of depreciation, to other utility plant, net. The net book value of these units at March 31, 2016 was approximately $60 million. Gulf Power has filed a petition with the Florida PSC requesting permission to create a regulatory asset for the remaining net book value of Plant Smith Units 1 and 2 and the remaining inventory associated with these units as of the retirement date. The retirement of these units is not expected to have a material impact on Gulf Power's financial statements as Gulf Power expects to recover these amounts through its rates; however, the ultimate outcome depends on future rate proceedings with the Florida PSC and cannot be determined at this time.

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

79

GULF POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

U.S. This litigation has included claims for damages alleged to have been caused by CO₂ and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.

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

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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

Recently Issued Accounting Standards

On February 25, 2016, the FASB issued ASU No. 2016-02, Leases(Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. Gulf Power is currently evaluating the new standard and has not yet determined its ultimate impact; however, adoption of ASU 2016-02 is expected to have a significant impact on Gulf Power's balance sheet.

On March 30, 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation(Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions. Most significantly, entities are required to recognize all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation as income tax expense or benefit in the income statement. Gulf Power currently recognizes any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation in additional paid-in capital. ASU 2016-09 is effective for fiscal years beginning after December 15, 2016, with early adoption permitted. Gulf Power is currently evaluating the new standard and has not yet determined its ultimate impact.

FINANCIAL CONDITION AND LIQUIDITY

Overview

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Gulf Power in Item 7 of the Form 10-K for additional information. Gulf Power's financial condition remained stable at March 31, 2016. Gulf Power intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit agreements to meet future capital and liquidity needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.

80

GULF POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Net cash provided from operating activities totaled $132 million for the first three months of 2016 compared to $81 million for the corresponding period in 2015. The $51 million increase in net cash was primarily due to a federal income tax refund and the timing of vendor payments. Net cash used for investing activities totaled $42 million in the first three months of 2016 primarily due to property additions to utility plant. Net cash used for financing activities totaled $116 million for the first three months of 2016 primarily due to payments related to notes payable and common stock dividends. Fluctuations in cash flow from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.

Significant balance sheet changes for the first three months of 2016 include decreases of $86 million in notes payable, $27 million of income tax receivables following the receipt of a federal income tax refund, and $26 million in cash and cash equivalents.

Capital Requirements and Contractual Obligations

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of 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, and trust funding requirements. Approximately $235 million will be required through March 31, 2017 to fund a maturity of long-term debt and an announced redemption of long-term debt. See "Financing Activities" herein for additional information.

The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; storm impacts; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing units, to meet regulatory requirements; changes in 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, external security issuances, term loans, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon regulatory approval, prevailing market conditions, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Gulf Power in Item 7 of the Form 10-K for additional information.

Gulf Power's current liabilities frequently exceed current assets because of the continued use of short-term debt as a funding source to meet scheduled maturities of long-term debt, as well as cash needs, which can fluctuate significantly due to the seasonality of the business. Gulf Power has substantial cash flow from operating activities and access to the capital markets and financial institutions to meet short-term liquidity needs, including its commercial paper program which is supported by bank credit facilities.

At March 31, 2016, Gulf Power had approximately $48 million of cash and cash equivalents. Committed credit arrangements with banks at March 31, 2016 were as follows:

Expires										Executable Term Loans				Due Within One Year
2016		2017		2018		Total		Unused		One Year		Two Years		Term Out		No Term Out
						(in millions)				(in millions)				(in millions)
$	75	$	40	$	165	$	280	$	280	$	45	$	—	$	45	$	40

81

GULF POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

Most of these bank credit arrangements contain covenants that limit debt levels and contain cross acceleration provisions to other indebtedness (including guarantee obligations) that are restricted only to the indebtedness of Gulf Power. Such cross acceleration provisions to other indebtedness would trigger an event of default if Gulf Power defaulted on indebtedness, the payment of which was then accelerated. Gulf Power is currently in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowings.

Subject to applicable market conditions, Gulf Power expects to renew or replace its bank credit arrangements, as needed, prior to expiration. In connection therewith, Gulf Power may extend the maturity dates and/or increase or decrease the lending commitments thereunder.

Most of the unused credit arrangements with banks are allocated to provide liquidity support to Gulf Power's pollution control revenue bonds and commercial paper program. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of March 31, 2016 was approximately $82 million. In addition, at March 31, 2016, Gulf Power had approximately $33 million of fixed rate pollution control revenue bonds outstanding that were required to be remarketed within the next 12 months.

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

Details of short-term borrowings were as follows:

	Short-term Debt at March 31, 2016				Short-term Debt During the Period(*)
	Amount Outstanding		Weighted Average Interest Rate		Average Amount Outstanding		Weighted Average Interest Rate		Maximum Amount Outstanding
	(in millions)				(in millions)				(in millions)
Commercial paper	$	56	0.9	%	$	77	0.8	%	$	148

(*) Average and maximum amounts are based upon daily balances during the three-month period ended March 31, 2016.

Gulf Power believes the need for working capital can be adequately met by utilizing the commercial paper program, lines of credit, short-term bank loans, and operating cash flows.

Credit Rating Risk

Gulf Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.

There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, transmission, and energy price risk management.

82

GULF POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The maximum potential collateral requirements under these contracts at March 31, 2016 were as follows:

Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB- and/or Baa3	$	78
Below BBB- and/or Baa3	$	428

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, a credit rating downgrade could impact the ability of Gulf Power to access capital markets and would be likely to impact the cost at which it does so.

Market Price Risk

Gulf Power's market risk exposure relative to interest rate changes for the first quarter 2016 has not changed materially compared to the December 31, 2015 reporting period. Gulf Power's exposure to market volatility in commodity fuel prices and prices of electricity with respect to its wholesale generating capacity is limited because its long-term sales agreements shift substantially all fuel cost responsibility to the purchaser. However, Gulf Power could become exposed to market volatility in energy-related commodity prices to the extent any wholesale generating capacity is uncontracted.

Through 2015, capacity revenues from long-term non-affiliate sales out of Gulf Power's ownership of Plant Scherer Unit 3 (205 MWs) represented the majority of Gulf Power's wholesale earnings. The capacity revenues associated with these contracts covering 100% of Gulf Power's ownership represented 82% of wholesale capacity revenues in 2015. Due to the expiration of a wholesale contract at the end of 2015 and another wholesale contract at the end of May 2016, Gulf Power's remaining contracted sales from the unit from June 2016 through 2019 will cover approximately 24% of the unit. The expiration of the contract in 2015 and the scheduled future expiration of the remaining contracts will have a material negative impact on Gulf Power's earnings in 2016 and may continue to have a material negative impact in future years until Gulf Power is able to find a suitable alternative related to this asset. The alternatives Gulf Power is actively evaluating include, without limitation, rededication of the asset to serve retail customers for whom it was originally planned and built, replacement long-term wholesale contracts or other sales into the wholesale market, or an asset sale. On May 5, 2016, Gulf Power delivered a letter to the Florida PSC requesting recognition of Gulf Power's ownership in Plant Scherer Unit 3 as being in service to retail customers when and as the contracts expire. The ultimate outcome of this matter cannot be determined at this time. 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 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.

Subsequent to March 31, 2016, Gulf Power announced the redemption in May 2016 of $125 million aggregate principal amount of its Series 2011A 5.75% Senior Notes due June 1, 2051.

83

MISSISSIPPI POWER COMPANY

84

MISSISSIPPI POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended March 31,
	2016			2015
	(in millions)
Operating Revenues:
Retail revenues	$	183		$	167
Wholesale revenues, non-affiliates	60			77
Wholesale revenues, affiliates	9			27
Other revenues	5			5
Total operating revenues	257			276
Operating Expenses:
Fuel	76			114
Purchased power, non-affiliates	—			2
Purchased power, affiliates	5			2
Other operations and maintenance	69			73
Depreciation and amortization	38			27
Taxes other than income taxes	26			25
Estimated loss on Kemper IGCC	53			9
Total operating expenses	267			252
Operating Income (Loss)	(10		)	24
Other Income and (Expense):
Allowance for equity funds used during construction	29			28
Interest expense, net of amounts capitalized	(16		)	(11		)
Other income (expense), net	(2		)	(2		)
Total other income and (expense)	11			15
Earnings Before Income Taxes	1			39
Income taxes (benefit)	(10		)	4
Net Income	11			35
Dividends on Preferred Stock	—			—
Net Income After Dividends on Preferred Stock	$	11		$	35

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended March 31,
	2016		2015
	(in millions)
Net Income	$	11	$	35
Other comprehensive income (loss):	—		—
Comprehensive Income	$	11	$	35

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

85

MISSISSIPPI POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Three Months Ended March 31,
	2016			2015
	(in millions)
Operating Activities:
Net income	$	11		$	35
Adjustments to reconcile net income    to net cash provided from (used for) operating activities —
Depreciation and amortization, total	39			26
Deferred income taxes	(4		)	141
Allowance for equity funds used during construction	(29		)	(28		)
Regulatory assets associated with Kemper IGCC	(6		)	(27		)
Estimated loss on Kemper IGCC	53			9
Other, net	1			11
Changes in certain current assets and liabilities —
-Receivables	45			17
-Fossil fuel stock	6			4
-Prepaid income taxes	(3		)	44
-Other current assets	(5		)	(3		)
-Accounts payable	(22		)	(22		)
-Accrued taxes	(61		)	(54		)
-Accrued interest	2			9
-Accrued compensation	(16		)	(20		)
-Over recovered regulatory clause revenues	9			22
-Mirror CWIP	—			40
-Customer liability associated with Kemper refunds	(51		)	—
-Other current liabilities	6			—
Net cash provided from (used for) operating activities	(25		)	204
Investing Activities:
Property additions	(197		)	(213		)
Construction payables	(7		)	(14		)
Other investing activities	(10		)	(6		)
Net cash used for investing activities	(214		)	(233		)
Financing Activities:
Proceeds —
Capital contributions from parent company	1			76
Long-term debt issuance to parent company	200			—
Other long-term debt issuances	900			—
Short-term borrowings	—			30
Redemptions —
Short-term borrowings	(475		)	—
Other long-term debt	(425		)	(75		)
Other financing activities	(2		)	(1		)
Net cash provided from financing activities	199			30
Net Change in Cash and Cash Equivalents	(40		)	1
Cash and Cash Equivalents at Beginning of Period	98			133
Cash and Cash Equivalents at End of Period	$	58		$	134
Supplemental Cash Flow Information:
Cash paid (received) during the period for --
Interest (paid $22 and $17, net of $10 and $18 capitalized for 2016 and 2015, respectively)	$	12		$	(1	)
Income taxes, net	(24		)	(180		)
Noncash transactions — Accrued property additions at end of period	97			100

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

86

MISSISSIPPI POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Assets	At March 31, 2016		At December 31, 2015
	(in millions)
Current Assets:
Cash and cash equivalents	$	58	$	98
Receivables —
Customer accounts receivable	23		26
Unbilled revenues	32		36
Income taxes receivable, current	—		20
Other accounts and notes receivable	6		10
Affiliated companies	7		20
Fossil fuel stock, at average cost	99		104
Materials and supplies, at average cost	76		75
Other regulatory assets, current	101		95
Prepaid income taxes	42		39
Other current assets	5		8
Total current assets	449		531
Property, Plant, and Equipment:
In service	4,905		4,886
Less accumulated provision for depreciation	1,287		1,262
Plant in service, net of depreciation	3,618		3,624
Construction work in progress	2,400		2,254
Total property, plant, and equipment	6,018		5,878
Other Property and Investments	11		11
Deferred Charges and Other Assets:
Deferred charges related to income taxes	303		290
Other regulatory assets, deferred	520		525
Income taxes receivable, non-current	544		544
Other deferred charges and assets	71		61
Total deferred charges and other assets	1,438		1,420
Total Assets	$	7,916	$	7,840

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

87

MISSISSIPPI POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholder's Equity	At March 31, 2016			At December 31, 2015
	(in millions)
Current Liabilities:
Securities due within one year	$	303		$	728
Notes payable	25			500
Accounts payable —
Affiliated	82			85
Other	108			135
Customer deposits	16			16
Accrued taxes	25			85
Accrued interest	21			18
Accrued compensation	10			26
Asset retirement obligations, current	39			22
Over recovered regulatory clause liabilities	106			96
Customer liability associated with Kemper refunds	22			73
Other current liabilities	55			52
Total current liabilities	812			1,836
Long-term Debt:
Long-term debt, affiliated	776			576
Long-term debt, non-affiliated	2,206			1,310
Total Long-term Debt	2,982			1,886
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	771			762
Deferred credits related to income taxes	8			8
Accumulated deferred investment tax credits	5			5
Employee benefit obligations	149			153
Asset retirement obligations, deferred	136			154
Unrecognized tax benefits	368			368
Other cost of removal obligations	167			165
Other regulatory liabilities, deferred	71			71
Other deferred credits and liabilities	41			40
Total deferred credits and other liabilities	1,716			1,726
Total Liabilities	5,510			5,448
Redeemable Preferred Stock	33			33
Common Stockholder's Equity:
Common stock, without par value —
Authorized — 1,130,000 shares
Outstanding — 1,121,000 shares	38			38
Paid-in capital	2,896			2,893
Accumulated deficit	(555		)	(566		)
Accumulated other comprehensive loss	(6		)	(6		)
Total common stockholder's equity	2,373			2,359
Total Liabilities and Stockholder's Equity	$	7,916		$	7,840

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

88

MISSISSIPPI POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

FIRST QUARTER 2016 vs. FIRST QUARTER 2015

OVERVIEW

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

Many factors affect the opportunities, challenges, and risks of Mississippi Power's business of selling electricity. These factors include Mississippi Power's ability to maintain and grow energy sales and to operate in a constructive regulatory environment that provides timely recovery of prudently-incurred costs. These costs include those related to the completion and operation of major construction projects, primarily the Kemper IGCC and the Plant Daniel scrubber project, projected long-term demand growth, reliability, fuel, and increasingly stringent environmental standards, as well as ongoing capital expenditures required for maintenance. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Mississippi Power for the foreseeable future.

In 2010, the Mississippi PSC issued a CPCN authorizing the acquisition, construction, and operation of the Kemper IGCC. The certificated cost estimate of the Kemper IGCC established by the Mississippi PSC was $2.4 billion with a construction cost cap of $2.88 billion, net of $245 million of grants awarded to the project by the DOE under the Clean Coal Power Initiative Round 2 (Initial 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). On April 8, 2016, Mississippi Power received approximately $137 million in additional grants from the DOE for the Kemper IGCC (Additional DOE Grants), which are expected to be used to reduce future rate impacts for customers.

Mississippi Power placed the combined cycle and the associated common facilities portion of the Kemper IGCC in-service in August 2014 and continues to focus on completing the remainder of the Kemper IGCC, including the gasifier and the gas clean-up facilities. The in-service date for the remainder of the Kemper IGCC is currently expected to occur in the third quarter 2016.

Mississippi Power's current cost estimate for the Kemper IGCC in total is approximately $6.58 billion, which includes approximately $5.35 billion of costs subject to the construction cost cap and is net of the Additional DOE Grants. Mississippi Power does not intend to seek any rate recovery for any related costs that exceed the $2.88 billion cost cap, net of the Initial DOE Grants and excluding the Cost Cap Exceptions. Mississippi Power recorded pre-tax charges to income for revisions to the cost estimate of $53 million ($33 million after tax) in the first quarter 2016. Since 2012, in the aggregate, Mississippi Power has incurred charges of $2.47 billion ($1.52 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through March 31, 2016. The current cost estimate includes costs through September 30, 2016.

In December 2015, the Mississippi PSC issued an order (In-Service Asset Rate Order), based on a stipulation (the 2015 Stipulation) between Mississippi Power and the Mississippi Public Utilities Staff (MPUS), authorizing rates that provide for the recovery of approximately $126 million annually related to Kemper IGCC assets previously placed in service. On February 25, 2016, Greenleaf CO2 Solutions, LLC filed a notice of appeal of the In-Service Asset Rate Order with the Mississippi Supreme Court (Court). On May 5, 2016, the Court dismissed the appeal. Further proceedings related to cost recovery for the Kemper IGCC are expected after the remainder of the Kemper IGCC is placed in service, which is currently expected to occur in the third quarter 2016. The ultimate outcome of these matters cannot be determined at this time.

For additional information on the Kemper IGCC, see Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and FUTURE EARNINGS

89

MISSISSIPPI POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

POTENTIAL – "Integrated Coal Gasification Combined Cycle" and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein.

On March 8, 2016, Mississippi Power entered into an unsecured term loan agreement for an aggregate amount of $1.2 billion to repay existing indebtedness and for other general corporate purposes. Mississippi Power borrowed $900 million under the term loan agreement and has the right to borrow the remaining $300 million on or before October 15, 2016. Mississippi Power used the initial proceeds to repay $900 million in maturing bank loans on March 8, 2016 and expects the remaining $300 million to be used to repay senior notes maturing in October 2016. The term loan pursuant to this agreement matures on April 1, 2018 and bears interest based on one-month LIBOR.

Mississippi Power continues to focus on several key performance indicators, including the construction, start-up, and rate recovery 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.

RESULTS OF OPERATIONS

Net Income

First Quarter 2016 vs. First Quarter 2015
(change in millions)	(% change)
$(24)	(68.6)

Mississippi Power's net income after dividends on preferred stock for the first quarter 2016 was $11 million compared to $35 million for the corresponding period in 2015. The decrease was primarily related to higher pre-tax charges of $53 million ($33 million after tax) in the first quarter 2016 compared to pre-tax charges of $9 million ($6 million after tax) in the first quarter 2015 for revisions of the estimated costs expected to be incurred on Mississippi Power's construction of the Kemper IGCC above the $2.88 billion cost cap established by the Mississippi PSC, net of the Initial DOE Grants and excluding the Cost Cap Exceptions. The decrease in net income was also related to a decrease in wholesale revenues and an increase in depreciation and amortization, partially offset by an increase in retail revenue due to the implementation of rates for certain Kemper IGCC in-service assets.

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

Retail Revenues

First Quarter 2016 vs. First Quarter 2015
(change in millions)	(% change)
$16	9.6

In the first quarter 2016, retail revenues were $183 million compared to $167 million for the corresponding period in 2015. Details of the changes in retail revenues were as follows:

90

MISSISSIPPI POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

	First Quarter 2016
	(in millions)			(% change)
Retail – prior year	$	167
Estimated change resulting from –
Rates and pricing	26			15.6
Sales growth	4			2.4
Weather	(3		)	(1.8	)
Fuel and other cost recovery	(11		)	(6.6	)
Retail – current year	$	183		9.6	%

Revenues associated with changes in rates and pricing increased in the first quarter 2016 when compared to the corresponding period in 2015, primarily due to the implementation of rates for certain Kemper IGCC in-service assets.

See Note 3 to the financial statements of Mississippi Power under "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 increased in the first quarter 2016 when compared to the corresponding period in 2015. Weather-adjusted KWH energy sales to residential customers increased 2.0% in the first quarter 2016 due to increased use per customer and customer growth. Weather-adjusted KWH energy sales to commercial customers increased 0.5% in the first quarter 2016 due to customer growth. KWH energy sales to industrial customers decreased 3.0% in the first quarter 2016 due to decreased usage by larger customers.

In the first quarter 2015, Mississippi Power updated the methodology to estimate the unbilled revenue allocation among customer classes. This change did not have a significant impact on net income. The KWH sales variances discussed above reflect an adjustment to the estimated allocation of Mississippi Power's unbilled first quarter 2015 KWH sales among customer classes that is consistent with the actual allocation in 2016. Without this adjustment, first quarter 2016 weather-adjusted residential KWH sales increased 8.5%, weather-adjusted commercial KWH sales increased 8.7%, and industrial KWH sales decreased 0.9% when compared to the corresponding period in 2015.

Fuel and other cost recovery revenues decreased in the first quarter 2016 when compared to the corresponding period in 2015, primarily as a result of lower recoverable fuel costs. See "Fuel and Purchased Power Expenses" herein for additional information. Recoverable fuel costs include fuel and purchased power expenses reduced by the fuel portion of wholesale revenues from energy sold to customers outside Mississippi Power's service territory. Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the energy component of purchased power costs, and do not affect net income.

Wholesale Revenues – Non-Affiliates

First Quarter 2016 vs. First Quarter 2015
(change in millions)	(% change)
$(17)	(22.1)

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 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 addition, Mississippi Power serves long-term contracts with rural electric cooperative associations and municipalities located in

91

MISSISSIPPI POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

southeastern Mississippi under cost-based electric tariffs which are subject to regulation by the FERC. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters" of Mississippi Power in Item 7 of the Form 10-K and – FUTURE EARNINGS POTENTIAL – "FERC Matters" herein for additional information.

In the first quarter 2016, wholesale revenues from sales to non-affiliates were $60 million compared to $77 million for the corresponding period in 2015. The decrease was primarily due to a $9 million decrease in capacity revenues primarily resulting from milder weather and decreased usage and an $8 million decrease in energy revenues primarily resulting from lower fuel prices.

Wholesale Revenues – Affiliates

First Quarter 2016 vs. First Quarter 2015
(change in millions)	(% change)
$(18)	(66.7)

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.

In the first quarter 2016, wholesale revenues from sales to affiliates were $9 million compared to $27 million for the corresponding period in 2015. The decrease was due to a $14 million decrease in KWH sales resulting from a decrease in sales from coal generation and a $4 million decrease associated with lower natural gas prices.

Fuel and Purchased Power Expenses

	First Quarter 2016 vs. First Quarter 2015
	(change in millions)			(% change)
Fuel	$	(38	)	(33.0)
Purchased power – non-affiliates	(2		)	(100.0)
Purchased power – affiliates	3			150.0
Total fuel and purchased power expenses	$	(37	)

In the first quarter 2016, total fuel and purchased power expenses were $81 million compared to $118 million for the corresponding period in 2015. The decrease was due to a $19 million decrease in the volume of KWHs generated and purchased and an $18 million decrease in the average cost of fuel.

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.

92

MISSISSIPPI POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

	First Quarter 2016	First Quarter 2015
Total generation (millions of KWHs)	3,588	4,345
Total purchased power (millions of KWHs)	261	114
Sources of generation (percent) –
Coal	11	22
Gas	89	78
Cost of fuel, generated (cents per net KWH) –
Coal	3.55	3.25
Gas	2.15	2.68
Average cost of fuel, generated (cents per net KWH)	2.32	2.82
Average cost of purchased power (cents per net KWH)	2.17	3.54

Fuel

In the first quarter 2016, fuel expense was $76 million compared to $114 million for the corresponding period in 2015. The decrease was due to a 19% decrease in the volume of KWHs generated, primarily as a result of milder weather, and an 18% decrease in the average cost of fuel per KWH generated primarily due to higher gas-fired generation, including the Kemper IGCC combined cycle that was placed in service in 2014. The decrease in volume included a decrease in coal-fired generation of 61% and a decrease in gas-fired generation of 5%.

Purchased Power

Energy purchases 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. Energy purchases from affiliates are made in accordance with the IIC, as approved by the FERC.

Other Operations and Maintenance Expenses

First Quarter 2016 vs. First Quarter 2015
(change in millions)	(% change)
$(4)	(5.5)

In the first quarter 2016, other operations and maintenance expenses were $69 million compared to $73 million for the corresponding period in 2015. The decrease was primarily due to a $9 million decrease in generation maintenance expenses due to lower outage costs, partially offset by a $7 million increase in generation maintenance expenses related to the combined cycle and the associated common facilities portion of the Kemper IGCC that Mississippi Power began expensing in the third quarter 2015 in connection with the implementation of interim rates associated with the Kemper IGCC in-service assets. See FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs – 2015 Rate Case" and " – Regulatory Assets and Liabilities" herein for additional information. See Note (F) to the Condensed Financial Statements herein for additional information related to pension costs.

93

MISSISSIPPI POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Depreciation and Amortization

First Quarter 2016 vs. First Quarter 2015
(change in millions)	(% change)
$11	40.7

In the first quarter 2016, depreciation and amortization was $38 million compared to $27 million for the corresponding period in 2015. The increase was primarily due to the amortization of certain regulatory assets associated with the Kemper IGCC.

See Note 1 to the financial statements of Mississippi Power under "Depreciation, Depletion, and Amortization" in Item 8 of the Form 10-K for additional information. Also, see Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.

Estimated Loss on Kemper IGCC

First Quarter 2016 vs. First Quarter 2015
(change in millions)	(% change)
$44	N/M

N/M – Not meaningful

In the first quarters of 2016 and 2015, estimated probable losses on the Kemper IGCC of $53 million and $9 million, respectively, were recorded at Mississippi Power. These losses reflect revisions of estimated costs expected to be incurred on the construction of the Kemper IGCC in excess of the $2.88 billion cost cap established by the Mississippi PSC, net of the Initial 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 Note (B) to the Condensed Financial Statements under "Integrated Coal Gasification Combined Cycle" herein for additional information.

Interest Expense, Net of Amounts Capitalized

First Quarter 2016 vs. First Quarter 2015
(change in millions)	(% change)
$5	45.5

In the first quarter 2016, interest expense, net of amounts capitalized was $16 million compared to $11 million for the corresponding period in 2015. The increase was primarily due to a decrease of $8 million in capitalized interest and interest increases of $4 million related to long-term debt, $3 million on unrecognized tax benefits, and $2 million related to short-term debt. These increases were partially offset by an $8 million decrease related to interest on deposits resulting from the termination of an asset purchase agreement between Mississippi Power and SMEPA in May 2015 and a $4 million decrease related to the required refund of Mirror CWIP.

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

94

MISSISSIPPI POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Income Taxes (Benefit)

First Quarter 2016 vs. First Quarter 2015
(change in millions)	(% change)
$(14)	N/M

N/M – Not meaningful

In the first quarter 2016, income tax benefit was $(10) million compared to an expense of $4 million for the corresponding period in 2015. The change was primarily due to the reduction in pre-tax earnings related to the estimated probable losses on 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 recover its prudently-incurred costs in a timely manner during a time of increasing costs, its ability to prevail against legal challenges associated with the Kemper IGCC, and the completion and subsequent operation of the Kemper IGCC in accordance with any operational parameters that may be adopted by the Mississippi PSC, as well as other ongoing construction projects. Future earnings in the near term will depend, in part, upon maintaining and growing sales which are subject to a number of factors. These factors include weather, competition, developing new and maintaining existing energy contracts and associated load requirements with other utilities and other wholesale customers, energy conservation practiced by customers, the use of alternative energy sources by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in Mississippi Power's service territory. Demand for electricity is primarily driven by economic growth. The pace of economic growth and electricity demand may be affected by changes in regional and global economic conditions, which may impact future earnings. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Mississippi Power in Item 7 of the Form 10-K.

Environmental Matters

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

Environmental Statutes and Regulations

Air Quality

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Air Quality" of Mississippi Power in Item 7 of the Form 10-K for additional information regarding the EPA's final MATS rule and regional haze regulations.

On April 25, 2016, in response to a June 2015 U.S. Supreme Court opinion, the EPA published its supplemental finding regarding consideration of costs in support of the MATS rule. This finding does not impact MATS rule

95

MISSISSIPPI POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

compliance requirements, costs, or deadlines, and all Mississippi Power units that are subject to the MATS rule have completed the measures necessary to achieve compliance with the MATS rule by the applicable deadlines.

Also on April 25, 2016, the EPA issued proposed revisions to the regional haze regulations. The ultimate impact of the proposed revisions will depend on their ultimate adoption, implementation, and any legal challenges and cannot be determined at this time.

FERC Matters

Municipal and Rural Associations Tariff

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

On March 31, 2016, Mississippi Power filed a request with the FERC for an increase in wholesale base revenues as agreed upon in the settlement agreement reached with its wholesale customers under the Municipal and Rural Associations (MRA) cost-based electric tariff. The settlement agreement provides that base rates under the MRA cost-based electric tariff will increase approximately $7 million annually, with revised rates effective for services rendered beginning May 1, 2016. The increase is primarily due to the Plant Daniel Units 1 and 2 scrubbers, which were placed in service in November 2015. Additionally, under the settlement agreement, the tariff customers agreed in principle to similar regulatory treatment for tariff ratemaking as the treatment approved for retail ratemaking under the In-Service Asset Rate Order. The Kemper IGCC regulatory treatment primarily includes (i) recovery of only the Kemper IGCC assets currently operational and providing service to customers and other related costs and (ii) removing all of the Kemper IGCC CWIP with a corresponding increase in accrual of AFUDC effective May 1, 2016. If approved by the FERC, the amount of base rate revenues to be recognized in 2016 is expected to be approximately $5 million. The additional resulting AFUDC is estimated to be approximately $6 million. The ultimate outcome of this matter cannot be determined at this time.

Retail Regulatory Matters

Mississippi Power's rates and charges for service to retail customers are subject to the regulatory oversight of the Mississippi PSC. Mississippi Power's rates are a combination of base rates and several separate cost recovery clauses for specific categories of costs. These separate cost recovery clauses address such items as fuel and purchased power, energy efficiency programs, ad valorem taxes, property damage, and the costs of compliance with environmental laws and regulations. Costs not addressed through one of the specific cost recovery clauses are recovered through Mississippi Power's base rates. See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters" and "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Retail Regulatory Matters – Mississippi Power" and "Integrated Coal Gasification Combined Cycle" herein for additional information.

96

MISSISSIPPI POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Renewables

In November 2015, the Mississippi PSC issued orders approving three solar facilities for a combined total of approximately 105 MWs. Mississippi Power will purchase all of the energy produced by the solar facilities for the 25-year term under each of the three PPAs, two of which were finalized as of December 31, 2015 and one of which was finalized as of March 2, 2016. The projects are expected to be in service by the end of 2016 and the resulting energy purchases are expected to be recovered through Mississippi Power's fuel cost recovery mechanism.

Performance Evaluation Plan

On April 1, 2016, Mississippi Power submitted its annual PEP lookback filing for 2015, which reflected the need for a $5 million surcharge to be recovered from customers. The filing has been suspended for review by the Mississippi PSC. The ultimate outcome of this matter cannot be determined at this time.

Fuel Cost Recovery

At March 31, 2016, the amount of over-recovered retail fuel costs included on the balance sheet was $80 million compared to over-recovered retail fuel costs of $71 million at December 31, 2015.

The Mississippi PSC conditionally approved a decrease of $120 million annually in fuel cost recovery rates on January 5, 2016, effective with the first billing cycle of February. As required by the order, on February 1, 2016, Mississippi Power submitted updated natural gas price forecasts and resulting fuel factors to the Mississippi PSC. If approved by the Mississippi PSC, the updated forecast would decrease fuel cost recovery rates by an additional $36 million annually. The ultimate outcome of this matter cannot be determined at this time.

Integrated Coal Gasification Combined Cycle

See Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K for information regarding Mississippi Power's construction of the Kemper IGCC.

Kemper IGCC Overview

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

Kemper IGCC Schedule and Cost Estimate

In 2012, the Mississippi PSC issued the 2012 MPSC CPCN Order, a detailed order confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing the acquisition, construction, and operation of the Kemper IGCC. The certificated cost estimate of the Kemper IGCC included in the 2012 MPSC CPCN Order was $2.4 billion, net of $245 million of Initial DOE Grants and excluding the cost of the lignite mine and equipment, the cost of the CO₂ pipeline facilities, and AFUDC related to the Kemper IGCC. The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, with recovery of prudently-incurred costs subject to approval by the Mississippi PSC. The Kemper IGCC was originally projected to be placed in service in May 2014. Mississippi Power placed the combined cycle and the associated common facilities portion of the Kemper IGCC in service using natural gas in August 2014 and currently expects to place the remainder of the Kemper IGCC, including the gasifier and the gas clean-up facilities, in service during the third quarter 2016.

97

MISSISSIPPI POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Recovery of the costs subject to the cost cap and the Cost Cap Exceptions remains subject to review and approval by the Mississippi PSC. Mississippi Power's Kemper IGCC 2010 project estimate, current cost estimate (which includes the impacts of the Court's decision discussed herein under "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order"), and actual costs incurred as of March 31, 2016, are as follows:

Cost Category	2010 Project Estimate(f)		Current Cost Estimate(a)			Actual Costs
	(in billions)
Plant Subject to Cost Cap(b)(g)	$	2.40	$	5.35		$	4.99
Lignite Mine and Equipment	0.21		0.23			0.23
CO2 Pipeline Facilities	0.14		0.11			0.12
AFUDC(c)	0.17		0.71			0.62
Combined Cycle and Related Assets Placed in Service – Incremental(d)(g)	—		0.02			0.01
General Exceptions	0.05		0.10			0.09
Deferred Costs(e)(g)	—		0.20			0.18
Additional DOE Grants	—		(0.14		)	—
Total Kemper IGCC	$	2.97	$	6.58		$	6.24

(a) Amounts in the Current Cost Estimate reflect estimated costs through September 30, 2016.

(b) The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, net of the Initial DOE Grants and excluding the Cost Cap Exceptions. The Current Cost Estimate and the Actual Costs include non-incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service in August 2014 that are subject to the $2.88 billion cost cap and exclude post-in-service costs for the lignite mine. See "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" herein for additional information. The Current Cost Estimate and the Actual Costs reflect 100% of the costs of the Kemper IGCC. See note (g) for additional information.

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

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

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

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

(g) Beginning in the third quarter 2015, certain costs, including debt carrying costs (associated with assets placed in service and other non-CWIP accounts), that previously were deferred as regulatory assets are now being recognized through income; however, such costs continue to be included in the Current Cost Estimate and the Actual Costs at March 31, 2016.

Of the total costs, including post-in-service costs for the lignite mine, incurred as of March 31, 2016, $3.61 billion was included in property, plant, and equipment (which is net of the Initial DOE Grants and estimated probable losses of $2.47 billion), $6 million in other property and investments, $75 million in fossil fuel stock, $45 million in materials and supplies, $22 million in other regulatory assets, current, $196 million in other regulatory assets, deferred, $1 million in other current assets, and $11 million in other deferred charges and assets in the balance sheet.

Mississippi Power does not intend to seek rate recovery for any costs related to the construction of the Kemper IGCC that exceed the $2.88 billion cost cap, net of the Initial DOE Grants and excluding the Cost Cap Exceptions. Mississippi Power recorded pre-tax charges to income for revisions to the cost estimate above the cost cap of $53 million($33 million after tax) in the first quarter 2016. Since 2012, in the aggregate, Mississippi Power has incurred charges of $2.47 billion ($1.52 billion after tax) as a result of changes in the cost estimate above the cost

98

MISSISSIPPI POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

cap for the Kemper IGCC through March 31, 2016. The increase to the cost estimate in the first quarter 2016 primarily reflects costs for the extension of the Kemper IGCC's projected in-service date through September 30, 2016, and increased efforts related to operational readiness and challenges in start-up and commissioning activities which includes the cost of repairs and modifications to the refractory lining inside the gasifiers. Any extension of the in-service date beyond September 30, 2016 is currently estimated to result in additional base costs of approximately $25 million to $35 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. However, additional costs may be required for remediation of any further equipment and/or design issues identified. Any extension of the in-service date with respect to the Kemper IGCC beyond September 30, 2016 would also increase costs for the Cost Cap Exceptions, which are not subject to the $2.88 billion cost cap established by the Mississippi PSC. These costs include AFUDC, which is currently estimated to total approximately $14 million per month, as well as carrying costs and operating expenses on Kemper IGCC assets placed in service and consulting and legal fees of approximately $2 million per month. For additional information, see "2015 Rate Case" herein.

Mississippi Power's analysis of the time needed to complete the start-up and commissioning activities for the Kemper IGCC will continue until the remaining Kemper IGCC assets are placed in service. 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 operating or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities for this first-of-a-kind technology (including major equipment failure and system integration), and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC). In subsequent periods, any further changes in the estimated costs to complete construction and start-up of the Kemper IGCC subject to the $2.88 billion cost cap, net of the Initial DOE Grants and excluding the Cost Cap Exceptions, will be reflected in Mississippi Power's statements of income and these changes could be material.

Rate Recovery of Kemper IGCC Costs

See "FERC Matters" herein for additional information regarding Mississippi Power's MRA cost based tariff relating to recovery of a portion of the Kemper IGCC costs from Mississippi Power's wholesale customers. Rate recovery of the retail portion of the Kemper IGCC is subject to the jurisdiction of the Mississippi PSC. See Note (G) to the Condensed Financial Statements under "Unrecognized Tax Benefits – Section 174 Research and Experimental Deduction" herein for additional tax information related to the Kemper IGCC.

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 future proceedings related to the operation of the Kemper IGCC. To the extent the Mississippi PSC determines the Kemper IGCC does not meet the operational parameters ultimately adopted by the Mississippi PSC or Mississippi Power incurs additional costs to satisfy such parameters, there could be a material adverse impact on Mississippi Power's financial statements.

99

MISSISSIPPI POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

2013 MPSC Rate Order

In January 2013, Mississippi Power entered into a settlement agreement with the Mississippi PSC that was intended to establish the process for resolving matters regarding cost recovery related to the Kemper IGCC (2013 Settlement Agreement). Under the 2013 Settlement Agreement, Mississippi Power agreed to limit the portion of prudently-incurred Kemper IGCC costs to be included in retail rate base to the $2.4 billion certificated cost estimate, plus the Cost Cap Exceptions, but excluding AFUDC, and any other costs permitted or determined to be excluded from the $2.88 billion cost cap by the Mississippi PSC. In March 2013, the Mississippi PSC issued a rate order approving retail rate increases of 15% effective March 19, 2013 and 3% effective January 1, 2014, which collectively were designed to collect $156 million annually beginning in 2014 (2013 MPSC Rate Order) to be used to mitigate customer rate impacts after the Kemper IGCC is placed in service, based on a mirror CWIP methodology (Mirror CWIP rate).

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. 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.

On February 12, 2015, the Court reversed the 2013 MPSC Rate Order based on, among other things, its findings that (1) the Mirror CWIP rate treatment was not provided for under the Baseload Act and (2) the Mississippi PSC should have determined the prudence of Kemper IGCC costs before approving rate recovery through the 2013 MPSC Rate Order. The Court also found the 2013 Settlement Agreement unenforceable due to a lack of public notice for the related proceedings. On July 7, 2015, the Mississippi PSC ordered that the Mirror CWIP rate be terminated effective July 20, 2015 and required the fourth quarter 2015 refund of the $342 million collected under the 2013 MPSC Rate Order, along with associated carrying costs of $29 million. The Court's decision did not impact the 2012 MPSC CPCN Order or the February 2013 legislation described below.

2015 Rate Case

As a result of the 2015 Court decision, on July 10, 2015, Mississippi Power filed a supplemental filing including a request for interim rates (Supplemental Notice) with the Mississippi PSC which presented an alternative rate proposal (In-Service Asset Proposal) designed to recover Mississippi Power's costs associated with the Kemper IGCC assets that are commercially operational and currently providing service to customers (the transmission facilities, combined cycle, natural gas pipeline, and water pipeline) and other related costs. On August 13, 2015, the Mississippi PSC approved the implementation of the requested interim rates designed to collect approximately $159 million annually effective with the first billing cycle in September 2015, subject to refund and certain other conditions.

On December 3, 2015, the Mississippi PSC issued the In-Service Asset Rate Order adopting in full the 2015 Stipulation entered into between Mississippi Power and the MPUS regarding the In-Service Asset Proposal. The In-Service Asset Rate Order provided for retail rate recovery of an annual revenue requirement of approximately $126 million, based on Mississippi Power's actual average capital structure, with a maximum common equity percentage of 49.733%, a 9.225% return on common equity, and actual embedded interest costs. The In-Service Asset Rate Order also included a prudence finding of all costs in the stipulated revenue requirement calculation for the in-service assets. The stipulated revenue requirement excluded the costs of the Kemper IGCC related to the 15% undivided interest that was previously projected to be purchased by SMEPA. Mississippi Power continues to evaluate its alternatives with respect to its investment and related costs associated with the 15% undivided interest.

With implementation of the new rate on December 17, 2015, the interim rates were terminated and, in March 2016, Mississippi Power completed customer refunds of approximately $11 million for the difference between the interim rates collected and the permanent rates.

Pursuant to the In-Service Asset Rate Order, Mississippi Power is required to file a subsequent rate request within 18 months. As part of the filing, Mississippi Power expects to request recovery of certain costs that the Mississippi PSC had excluded from the revenue requirement calculation.

100

MISSISSIPPI POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

On February 25, 2016, Greenleaf CO2 Solutions, LLC filed a notice of appeal of the In-Service Asset Rate Order with the Court. On May 5, 2016, the Court dismissed the appeal.

Legislation to authorize a multi-year rate plan and legislation to provide for alternate financing through securitization of up to $1.0 billion of prudently-incurred costs was enacted into law in 2013. Mississippi Power expects to securitize prudently-incurred qualifying facility costs in excess of the certificated cost estimate of $2.4 billion. Qualifying facility costs include, but are not limited to, pre-construction costs, construction costs, regulatory costs, and accrued AFUDC. The Court's decision regarding the 2013 MPSC Rate Order did not impact Mississippi Power's ability to utilize alternate financing through securitization or the February 2013 legislation.

Mississippi Power expects to seek additional rate relief to address recovery of the remaining Kemper IGCC assets. In addition to current estimated costs at March 31, 2016 of $6.58 billion, Mississippi Power anticipates that it will incur additional costs after the Kemper IGCC in-service date until the Kemper IGCC cost recovery approach is finalized. These costs include, but are not limited to, regulatory costs and additional carrying costs which could be material. Recovery of these costs would be subject to approval by the Mississippi PSC.

Regulatory Assets and Liabilities

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

In August 2014, Mississippi Power requested confirmation by the Mississippi PSC of Mississippi Power's authority to defer all operating expenses associated with the operation of the combined cycle subject to review of such costs by the Mississippi PSC. In addition, Mississippi Power is authorized to accrue carrying costs on the unamortized balance of such regulatory assets at a rate and in a manner to be determined by the Mississippi PSC in future cost recovery mechanism proceedings. Beginning in the third quarter 2015, in connection with the implementation of interim rates, Mississippi Power began expensing certain ongoing project costs and certain debt carrying costs (associated with assets placed in service and other non-CWIP accounts) that previously were deferred as regulatory assets and began amortizing certain regulatory assets associated with assets placed in service and consulting and legal fees. The amortization periods for these regulatory assets vary from two years to 10 years as set forth in the In-Service Asset Rate Order. As of March 31, 2016, the balance associated with these regulatory assets was $120 million, of which $22 million is included in current assets. Other regulatory assets associated with the remainder of the Kemper IGCC totaled $98 million as of March 31, 2016. The amortization period for these assets is expected to be determined by the Mississippi PSC in future rate proceedings following completion of construction and start-up of the Kemper IGCC and related prudence reviews.

See "2013 MPSC Rate Order" herein for information related to the July 7, 2015 Mississippi PSC order terminating the Mirror CWIP rate and requiring refund of collections under Mirror CWIP.

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

The In-Service Asset Rate Order requires Mississippi Power to submit an annual true-up calculation of its actual cost of capital, compared to the stipulated total cost of capital, with the first occurring as of May 31, 2016. As of March 31, 2016, Mississippi Power recorded a related regulatory liability of approximately $3 million. See "2015 Rate Case" herein for additional information.

Lignite Mine and CO₂ Pipeline Facilities

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

101

MISSISSIPPI POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 Denbury and Treetop with termination rights as Mississippi Power has not satisfied its contractual obligation to deliver captured CO₂ by May 11, 2015. Since May 11, 2015, Mississippi Power has been engaged in ongoing discussions with its off-takers regarding the status of the CO₂ delivery schedule as well as other issues related to the CO₂ agreements. As a result of discussions with Treetop, on August 3, 2015, Mississippi Power agreed to amend certain provisions of their agreement that do not affect pricing or minimum purchase quantities. Potential requirements imposed on CO₂ off-takers under the Clean Power Plan (if ultimately enacted in its current form, pending resolution of litigation) and the potential adverse financial impact of low oil prices on the off-takers increase the risk that the CO₂ contracts may be terminated or materially modified. Any termination or material modification of these agreements could result in a material reduction in Mississippi Power's revenues to the extent Mississippi Power is not able to enter into other similar contractual arrangements. Additionally, if the contracts remain in place, sustained oil price reductions could result in significantly lower revenues than Mississippi Power forecasted to be available to offset customer rate impacts, which could have a material impact on Mississippi Power's financial statements. 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 Clean Power Plan and related litigation.

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

Civil Lawsuit

On April 26, 2016, a complaint against Mississippi Power was filed in Harrison County Circuit Court by Biloxi Freezing & Processing Inc., Gulfside Casino Partnership, and John Carlton Dean. The plaintiffs allege that Mississippi Power violated the Mississippi Unfair Trade Practices Act and concealed, falsely represented, and failed to fully disclose important facts concerning the cost and schedule of the Kemper IGCC and that Mississippi Power's alleged breaches interfered with and destroyed economically advantageous relationships between the plaintiffs and their current and prospective business associates. The plaintiffs seek unspecified actual damages and punitive damages as well as attorney's fees, costs, and interest. The plaintiffs also seek an injunction to prevent any Kemper IGCC costs from being charged to customers through electric rates. Mississippi Power believes this legal challenge has no merit; however, an adverse outcome in this proceeding could have a material impact on Mississippi Power's results of operations, financial condition, and liquidity. Mississippi Power will vigorously defend the matter, and the final outcome of this matter cannot be determined at this time.

Income Tax Matters

See MANAGEMENT'S DISCUSSION AND ANALYSIS - FUTURE EARNINGS POTENTIAL - "Income Tax Matters" of Mississippi Power in Item 7 of the Form 10-K and Note (G) to the Condensed Financial Statements under "Section 174 Research and Experimental Deduction" herein for additional information.

102

MISSISSIPPI POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Other Matters

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

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

The SEC is conducting a formal investigation of Southern Company and Mississippi Power concerning the estimated costs and expected in-service date of the Kemper IGCC. Southern Company and Mississippi Power believe the investigation is focused primarily on periods subsequent to 2010 and on accounting matters, disclosure controls and procedures, and internal controls over financial reporting associated with the Kemper IGCC. See ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" herein for additional information on the Kemper IGCC estimated construction costs and expected in-service date. Southern Company and Mississippi Power are cooperating fully with the SEC. The ultimate outcome of this matter cannot be determined at this time; however, it is not expected to have a material impact on the financial statements of Mississippi Power.

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

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

During 2016, Mississippi Power further revised its cost estimate to complete construction and start-up of the Kemper IGCC to an amount that exceeds the $2.88 billion cost cap, net of the Initial DOE Grants and excluding the Cost Cap Exceptions. Mississippi Power does not intend to seek any rate recovery for any costs related to the construction of the Kemper IGCC that exceed the $2.88 billion cost cap, net of the Initial 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 $53 million ($33 million after tax) in the first quarter 2016, $183 million ($113 million after tax) in the fourth quarter 2015, $150 million ($93 million after tax) in the third

103

MISSISSIPPI POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

quarter 2015, $23 million ($14 million after tax) in the second quarter 2015, $9 million ($6 million after tax) in the first quarter 2015, $70 million ($43 million after tax) in the fourth quarter 2014, $418 million ($258 million after tax) in the third quarter 2014, $380 million ($235 million after tax) in the first quarter 2014, $40 million ($25 million after tax) in the fourth quarter 2013, $150 million ($93 million after tax) in the third quarter 2013, $450 million ($278 million after tax) in the second quarter 2013, $462 million ($285 million after tax) in the first quarter 2013, and $78 million ($48 million after tax) in the fourth quarter 2012. In the aggregate, Mississippi Power has incurred charges of $2.47 billion ($1.52 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through March 31, 2016.

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

Mississippi Power's revised cost estimate includes costs through September 30, 2016. Any extension of the in-service date beyond September 30, 2016 is currently estimated to result in additional base costs of approximately $25 million to $35 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. However, additional costs may be required for remediation of any further equipment and/or design issues identified. Any extension of the in-service date with respect to the Kemper IGCC beyond September 30, 2016 would also increase costs for the Cost Cap Exceptions, which are not subject to the $2.88 billion cost cap established by the Mississippi PSC. These costs include AFUDC, which is currently estimated to total approximately $14 million per month, as well as carrying costs and operating expenses on Kemper IGCC assets placed in service and consulting and legal fees of approximately $2 million per month.

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

Recently Issued Accounting Standards

On February 25, 2016, the FASB issued ASU No. 2016-02, Leases(Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. Mississippi Power is currently evaluating the new standard and has not yet determined its ultimate impact; however, adoption of ASU 2016-02 is expected to have a significant impact on Mississippi Power's balance sheet.

On March 30, 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation(Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions. Most

104

MISSISSIPPI POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

significantly, entities are required to recognize all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation as income tax expense or benefit in the income statement. Mississippi Power currently recognizes any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation in additional paid-in capital. ASU 2016-09 is effective for fiscal years beginning after December 15, 2016, with early adoption permitted. Mississippi Power is currently evaluating the new standard and has not yet determined its ultimate impact.

FINANCIAL CONDITION AND LIQUIDITY

Overview

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Mississippi Power in Item 7 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle" herein for additional information. Earnings for the three months ended March 31, 2016 were negatively affected by revisions to the cost estimate for the Kemper IGCC.

Through March 31, 2016, Mississippi Power has incurred non-recoverable cash expenditures of $2.11 billion and is expected to incur approximately $0.36 billion in additional non-recoverable cash expenditures through completion of the construction and start-up of the Kemper IGCC.

For the three-year period from 2016 through 2018, Mississippi Power's capital expenditures and debt maturities are expected to materially exceed operating cash flows. In addition to the Kemper IGCC, projected capital expenditures in that period include investments to maintain existing generation facilities, to add environmental modifications to existing generating units, to add or change fuel sources for certain existing units, and to expand and improve transmission and distribution facilities.

On January 28, 2016, Mississippi Power issued a promissory note for up to $275 million to Southern Company, which matures in December 2017, bearing interest based on one-month LIBOR. During the first three months of 2016, Mississippi Power borrowed $100 million under this promissory note. In addition, on January 19, 2016, Mississippi Power borrowed an additional $100 million from Southern Company pursuant to a promissory note issued in November 2015. On March 8, 2016, Mississippi Power entered into an unsecured term loan agreement for an aggregate amount of $1.2 billion to repay existing indebtedness and for other general corporate purposes. Mississippi Power borrowed $900 million under the term loan agreement and has the right to borrow the remaining $300 million on or before October 15, 2016.

As of March 31, 2016, Mississippi Power's current liabilities exceeded current assets by approximately $363 million primarily due to $300 million in senior notes scheduled to mature on October 15, 2016 and $25 million in short-term debt. Mississippi Power intends to utilize operating cash flows and lines of credit (to the extent available) as well as loans and, under certain circumstances, equity contributions from Southern Company to fund the remainder of its capital needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.

Net cash used for operating activities totaled $25 million for the first three months of 2016, a decrease of $229 million as compared to the corresponding period in 2015. The decrease in cash provided from operating activities is primarily due to lower research and experimental tax deductions, a reduction in the customer liability associated with Kemper IGCC refunds due to offsetting service provided, a decrease in prepaid income taxes, and a decrease in Mirror CWIP regulatory liability due to the Mirror CWIP refund, partially offset by an increase in receivables. See Notes (B) and (G) to the Condensed Financial Statements herein for additional information. Net cash used for investing activities totaled $214 million for the first three months of 2016 primarily due to gross property additions related to the Kemper IGCC. Net cash provided from financing activities totaled $199 million for the first three months of 2016 primarily due to long-term debt issuances, partially offset by redemptions of long-term debt and short-term borrowings. Fluctuations in cash flow from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.

105

MISSISSIPPI POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Significant balance sheet changes for the first three months of 2016 include an increase in long-term debt of $1.1 billion. A portion of this debt was used to repay securities and notes payable resulting in a $425 million decrease in securities due within one year and a $475 million decrease in notes payable. Total property, plant, and equipment increased $140 million primarily due to the construction and startup activities for the Kemper IGCC. The customer liability associated with Kemper IGCC refunds decreased $51 million.

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 $300 million will be required through March 31, 2017 to fund maturities of long-term debt, and $25 million will be required to fund maturities of short-term debt. See "Sources of Capital" herein for additional information.

The construction program of Mississippi Power is currently estimated to be $841 million for 2016, $216 million for 2017, and $264 million for 2018, which includes expenditures related to the construction of the Kemper IGCC of $665 million in 2016.

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

Sources of Capital

In December 2015, the Mississippi PSC approved the In-Service Asset Rate Order, which among other things, provided for retail rate recovery of an annual revenue requirement of approximately $126 million effective December 17, 2015. The amount, type, and timing of future financings will depend upon regulatory approval, prevailing market conditions, and other factors, which includes resolution of Kemper IGCC cost recovery. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" and – FUTURE EARNINGS POTENTIAL – "Integrated Coal Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" and " – 2015 Rate Case" of Mississippi Power in Item 7 of the Form 10-K for additional information. Also see MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Bonus Depreciation" of Mississippi Power in Item 7 of the Form 10-K for additional information.

Mississippi Power received $245 million of Initial DOE Grants in prior years that were used for the construction of the Kemper IGCC. An additional $25 million of grants from the DOE is expected to be received for commercial operation of the Kemper IGCC. On April 8, 2016, Mississippi Power received approximately $137 million in Additional DOE Grants for the Kemper IGCC, which are expected to be used to reduce future rate impacts for customers. In addition, see Note 3 to the financial statements of Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K for information regarding legislation related to the securitization of certain costs of the Kemper IGCC.

106

MISSISSIPPI POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

On January 28, 2016, Mississippi Power issued a promissory note for up to $275 million to Southern Company, which matures in December 2017, bearing interest based on one-month LIBOR. During the first three months of 2016, Mississippi Power borrowed $100 million from Southern Company pursuant to the $275 million promissory note with a $50 million draw occurring on each of January 29, 2016 and March 14, 2016. In addition, on January 19, 2016, Mississippi Power borrowed $100 million from Southern Company pursuant to a promissory note issued in November 2015. On March 8, 2016, Mississippi Power entered into an unsecured term loan agreement for an aggregate amount of $1.2 billion to repay existing indebtedness and for other general corporate purposes. Mississippi Power borrowed $900 million under the term loan agreement and has the right to borrow the remaining $300 million on or before October 15, 2016. Mississippi Power used the initial proceeds to repay $900 million in maturing bank loans on March 8, 2016 and expects the remaining $300 million to be used to repay senior notes maturing in October 2016. The term loan pursuant to this agreement matures on April 1, 2018 and bears interest based on one-month LIBOR.

Mississippi Power intends to utilize operating cash flows and lines of credit (to the extent available) as well as loans and, under certain circumstances, equity contributions from Southern Company to fund Mississippi Power's short-term capital needs.

At March 31, 2016, Mississippi Power had approximately $58 million of cash and cash equivalents. Committed credit arrangements with banks at March 31, 2016 were as follows:

Expires						Executable Term Loans				Due Within One Year
2016		Total		Unused		One Year		Two Years		Term Out		No Term Out
		(in millions)				(in millions)				(in millions)
$	205	$	205	$	180	$	30	$	15	$	45	$	160

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

Most of these bank credit arrangements, as well as Mississippi Power's term loan arrangements, contain covenants that limit debt levels and typically contain cross acceleration or 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 specific threshold. Such cross acceleration provisions to other indebtedness would trigger an event of default if Mississippi Power defaulted on indebtedness, the payment of which was then accelerated. Mississippi Power is in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowing.

Subject to applicable market conditions, Mississippi Power expects to seek to renew or replace its credit arrangements, as needed prior to expiration. In connection therewith, Mississippi Power may extend the maturity dates and/or increase or decrease the lending commitments thereunder.

A portion of the $180 million unused credit arrangements with banks is allocated to provide liquidity support to Mississippi Power's pollution control revenue bonds and commercial paper borrowings. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of March 31, 2016 was approximately $40 million.

107

MISSISSIPPI POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Details of short-term borrowings were as follows:

	Short-term Debt at March 31, 2016			Short-term Debt During the Period(*)
	Amount Outstanding		Weighted Average Interest Rate	Average Amount Outstanding		Weighted Average Interest Rate	Maximum Amount Outstanding
	(in millions)			(in millions)			(in millions)
Short-term bank debt	$	25	2.1%	$	375	2.0%	$	500

(*) Average and maximum amounts are based upon daily balances during the three-month period ended March 31, 2016.

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 have required or could require collateral, but not accelerated payment, in the event of a credit rating change to BBB and/or Baa2 or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, energy price risk management, and transmission. At March 31, 2016, the maximum potential collateral requirements under these contracts at a rating of BBB and/or Baa2 or BBB- and/or Baa3 was not material. The maximum potential collateral requirements at a rating below BBB- and/or Baa3 equaled approximately $266 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, a credit rating downgrade could impact the ability of Mississippi Power to access capital markets, and would be likely to impact the cost at which it does so.

Financing Activities

In January 2016, Mississippi Power issued a floating rate promissory note to Southern Company in an aggregate principal amount of up to $275 million, which matures on December 1, 2017, bearing interest based on one-month LIBOR. As of March 31, 2016, Mississippi Power had borrowed $100 million under this promissory note with a $50 million draw occurring on each of January 29, 2016 and March 14, 2016. In addition, on January 19, 2016, Mississippi Power borrowed $100 million from Southern Company pursuant to a promissory note issued in November 2015.

On March 8, 2016, Mississippi Power entered into an unsecured term loan agreement for an aggregate amount of $1.2 billion to repay existing indebtedness and for other general corporate purposes. Mississippi Power borrowed $900 million under the term loan agreement and has the right to borrow the remaining $300 million on or before October 15, 2016, upon satisfaction of certain customary conditions. Mississippi Power used the initial proceeds to repay $900 million in maturing bank notes on March 8, 2016 and expects the remaining $300 million to be used to repay senior notes maturing in October 2016. The term loan pursuant to this agreement matures on April 1, 2018 and bears interest based on one-month LIBOR.

Also in March 2016, Mississippi Power renewed a $10 million short-term note, which matures on June 30, 2016, bearing interest based on three-month LIBOR.

108

SOUTHERN POWER COMPANY

AND SUBSIDIARY COMPANIES

109

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended March 31,
	2016			2015
	(in millions)
Operating Revenues:
Wholesale revenues, non-affiliates	$	215		$	232
Wholesale revenues, affiliates	97			114
Other revenues	3			2
Total operating revenues	315			348
Operating Expenses:
Fuel	91			138
Purchased power, non-affiliates	13			16
Purchased power, affiliates	6			10
Other operations and maintenance	79			52
Depreciation and amortization	73			59
Taxes other than income taxes	6			6
Total operating expenses	268			281
Operating Income	47			67
Other Income and (Expense):
Interest expense, net of amounts capitalized	(21		)	(22		)
Other income (expense), net	2			—
Total other income and (expense)	(19		)	(22		)
Earnings Before Income Taxes	28			45
Income taxes (benefit)	(23		)	12
Net Income	51			33
Less: Net income attributable to noncontrolling interests	1			—
Net Income Attributable to Southern Power	$	50		$	33

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended March 31,
	2016		2015
	(in millions)
Net Income	$	51	$	33
Other comprehensive income (loss):
Qualifying hedges:
Reclassification adjustment for amounts included in net income, net of tax of $-, and $-, respectively	1		—
Total other comprehensive income (loss)	1		—
Less: Comprehensive income attributable to noncontrolling interests	1		—
Comprehensive Income Attributable to Southern Power	$	51	$	33

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

110

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Three Months Ended March 31,
	2016			2015
	(in millions)
Operating Activities:
Net income	$	51		$	33
Adjustments to reconcile net income to net cash used for operating activities —
Depreciation and amortization, total	75			60
Deferred income taxes	(132		)	(54		)
Amortization of investment tax credits	(7		)	(4		)
Deferred revenues	(26		)	(20		)
Other, net	9			3
Changes in certain current assets and liabilities —
-Receivables	(3		)	2
-Fossil fuel stock	1			6
-Prepaid income taxes	(31		)	(2		)
-Accounts payable	(12		)	(25		)
-Accrued taxes	(37		)	(4		)
-Accrued interest	2			(15		)
-Other current liabilities	—			1
Net cash used for operating activities	(110		)	(19		)
Investing Activities:
Plant acquisitions	(114		)	(6		)
Property additions	(767		)	(33		)
Change in construction payables	31			17
Payments pursuant to long-term service agreements	(25		)	(16		)
Investment in restricted cash	(289		)	—
Distribution of restricted cash	292			—
Other investing activities	(1		)	—
Net cash used for investing activities	(873		)	(38		)
Financing Activities:
Increase in notes payable, net	276			38
Distributions to noncontrolling interests	(4		)	—
Capital contributions from noncontrolling interests	131			—
Purchase of membership interests from noncontrolling interests	(129		)	—
Payment of common stock dividends	(68		)	(33		)
Net cash provided from financing activities	206			5
Net Change in Cash and Cash Equivalents	(777		)	(52		)
Cash and Cash Equivalents at Beginning of Period	830			75
Cash and Cash Equivalents at End of Period	$	53		$	23
Supplemental Cash Flow Information:
Cash paid (received) during the period for --
Interest (net of $10 and $- capitalized for 2016 and 2015, respectively)	$	15		$	36
Income taxes, net	188			79
Noncash transactions — Accrued property additions at end of period	262			16

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

111

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

Assets	At March 31, 2016		At December 31, 2015
	(in millions)
Current Assets:
Cash and cash equivalents	$	53	$	830
Receivables —
Customer accounts receivable	76		75
Other accounts receivable	23		19
Affiliated companies	31		30
Fossil fuel stock, at average cost	14		16
Materials and supplies, at average cost	63		63
Prepaid income taxes	77		45
Other prepaid expenses	23		23
Assets from risk management activities	6		7
Total current assets	366		1,108
Property, Plant, and Equipment:
In service	7,738		7,275
Less accumulated provision for depreciation	1,299		1,248
Plant in service, net of depreciation	6,439		6,027
Construction work in progress	1,535		1,137
Total property, plant, and equipment	7,974		7,164
Other Property and Investments:
Goodwill	2		2
Other intangible assets, net of amortization of $13 and $12 at March 31, 2016 and December 31, 2015, respectively	316		317
Total other property and investments	318		319
Deferred Charges and Other Assets:
Prepaid long-term service agreements	184		166
Other deferred charges and assets — affiliated	20		9
Other deferred charges and assets — non-affiliated	137		139
Total deferred charges and other assets	341		314
Total Assets	$	8,999	$	8,905

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

112

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholders' Equity	At March 31, 2016		At December 31, 2015
	(in millions)
Current Liabilities:
Securities due within one year	$	401	$	403
Notes payable	413		137
Accounts payable —
Affiliated	62		66
Other	347		327
Accrued taxes —
Accrued income taxes	9		198
Other accrued taxes	16		5
Accrued interest	25		23
Contingent consideration	21		36
Other current liabilities	49		44
Total current liabilities	1,343		1,239
Long-term Debt	2,722		2,719
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	470		601
Accumulated deferred investment tax credits	1,025		889
Accrued income taxes, non-current	109		109
Asset retirement obligations	25		21
Deferred capacity revenues — affiliated	6		17
Other deferred credits and liabilities	11		3
Total deferred credits and other liabilities	1,646		1,640
Total Liabilities	5,711		5,598
Redeemable Noncontrolling Interests	44		43
Common Stockholder's Equity:
Common stock, par value $.01 per share --
Authorized - 1,000,000 shares
Outstanding - 1,000 shares	—		—
Paid-in capital	1,821		1,822
Retained earnings	640		657
Accumulated other comprehensive income	5		4
Total common stockholder's equity	2,466		2,483
Noncontrolling Interests	778		781
Total Stockholders' Equity	3,244		3,264
Total Liabilities and Stockholders' Equity	$	8,999	$	8,905

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

113

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

FIRST QUARTER 2016 vs. FIRST QUARTER 2015

OVERVIEW

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

During the three months ended March 31, 2016, Southern Power acquired or commenced construction of approximately 140 MWs of additional solar facilities. Southern Power also entered into an agreement to acquire an approximately 40-MW wind facility located in Maine. Subsequent to March 31, 2016, Southern Power acquired an approximately 151-MW wind facility located in Oklahoma. See FUTURE EARNINGS POTENTIAL – "Acquisitions" and "Construction Projects" herein for additional information.

At March 31, 2016, Southern Power had an average investment coverage ratio of 91% for the next five years (through 2020) and 90% for the next 10 years (through 2025) with an average remaining contract duration of approximately 18 years. This includes the PPAs and capacity associated with solar facilities currently under construction and acquisitions discussed herein. See FUTURE EARNINGS POTENTIAL – "Power Sales Agreements" herein for additional information.

Southern Power continues to focus on several key performance indicators. These indicators include peak season equivalent forced outage rate, contract availability, and net income. For additional information on these indicators, see MANAGEMENT'S DISCUSSION AND ANALYSIS – OVERVIEW – "Key Performance Indicators" of Southern Power in Item 7 of the Form 10-K.

RESULTS OF OPERATIONS

Net Income

First Quarter 2016 vs. First Quarter 2015
(change in millions)	(% change)
$17	51.5

Net income attributable to Southern Power for the first quarter 2016 was $50 million compared to $33 million for the corresponding period in 2015. The increase was primarily due to increased tax benefits from solar ITCs and wind PTCs and increased renewable energy sales arising from new solar and wind facilities, partially offset by increases in depreciation and operations and maintenance expenses.

Operating Revenues

First Quarter 2016 vs. First Quarter 2015
(change in millions)	(% change)
$(33)	(9.5)

Operating revenues include PPA capacity revenues which are derived primarily from long-term contracts involving natural gas and biomass generating facilities, and PPA energy revenues which include sales from natural gas, biomass, solar, and wind facilities. To the extent Southern Power has unused capacity, it may sell power into the wholesale market or into the power pool.

114

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

	First Quarter 2016 vs. First Quarter 2015
	(change in millions)			(% change)
PPA capacity revenues	$	(3	)	(2.1)
PPA energy revenues	—			N/M
Total PPA revenues	(3		)	(1.1)
Revenue not covered by PPA	(31		)	(30.0)
Other revenues	1			50.0
Total operating revenues	$	(33	)	(9.5)%

N/M – Not meaningful

In the first quarter 2016, operating revenues were $315 million compared to $348 million for the corresponding period in 2015. The $33 million decrease in operating revenues was primarily due to the following:

• PPA capacity revenues decreased $3 million as a result of a $15 million decrease in non-affiliate capacity revenues, partially offset by a $12 million increase in affiliate capacity revenues primarily due to PPA remarketing.

• PPA energy revenuesremained flat; however, a $20 million increase in renewable energy sales, arising from new solar and wind facilities, was offset by a decrease of $20 million in fuel revenues related to natural gas PPAs.

• Revenues not covered by PPA decreased $31 million primarily due to a 23% decrease in non-PPA KWH sales associated with increased scheduled outages and a reduction in demand driven by milder weather in 2016 as compared to 2015.

Wholesale revenues will vary depending on the energy demand of Southern Power's 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 under PPAs 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.

Capacity revenues are an integral component of Southern Power's natural gas and biomass PPAs and generally represent the greatest contribution to net income. Energy under the PPAs is generally sold at variable cost or is indexed to published gas indices. Energy revenues also include fees for support services, fuel storage, and unit start charges.

Southern Power's electricity sales from solar and wind generating facilities are also through long-term PPAs, but do not have a capacity charge. Instead, the customers purchase the energy output of a dedicated renewable facility through an energy charge. As a result, Southern Power's ability to recover fixed and variable operations and maintenance expenses is dependent upon the level of energy generated from these facilities, which can be impacted by weather conditions, equipment performance, and other factors.

115

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Fuel and Purchased Power Expenses

Fuel costs constitute the single largest expense for Southern Power. Additionally, Southern Power purchases a portion of its electricity needs from the wholesale market. Details of Southern Power's generation and purchased power were as follows:

	First Quarter 2016	First Quarter 2015
Generation (in billions of KWHs)	7.7	7.9
Purchased power (in billions of KWHs)	0.6	0.5
Total generation and purchased power	8.3	8.4
Total generation and purchased power (excluding solar, wind and tolling)	5.3	5.9

Southern Power's PPAs for natural gas and biomass generation generally provide that the purchasers are responsible for either procuring the fuel (tolling agreements) or reimbursing Southern Power for substantially all of the cost of fuel relating to the energy delivered under such PPAs. Consequently, any increase or decrease in such fuel costs is generally accompanied by an increase or decrease in related fuel revenues under the PPAs 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 wholesale market or into the power pool, for capacity owned directly by Southern Power (excluding its subsidiaries).

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, affiliate companies, or external parties.

	First Quarter 2016 vs. First Quarter 2015
	(change in millions)			(% change)
Fuel	$	(47	)	(34.1)
Purchased power	(7		)	(26.9)
Total fuel and purchased power expenses	$	(54	)

In the first quarter 2016, total fuel and purchased power expenses were $110 million compared to $164 million for the corresponding period in 2015. The decrease was primarily due to the following:

• Fuel expense decreased $47 million primarily due to a $28 million decrease associated with the average cost of natural gas per KWH generated and a $19 million decrease associated with the volume of KWHs generated.

• Purchased power expense decreased $7 million due to a $12 million decrease in the average cost of purchased power and a $4 million decrease associated with a PPA expiration, partially offset by a $9 million increase associated with the volume of KWHs purchased.

Other Operations and Maintenance Expenses

First Quarter 2016 vs. First Quarter 2015
(change in millions)	(% change)
$27	51.9

In the first quarter 2016, other operations and maintenance expenses were $79 million compared to $52 million for the corresponding period in 2015. The increase was primarily due to a $14 million increase associated with

116

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

scheduled outage and maintenance expenses, a $6 million increase in business support services expenses, and a $5 million increase in expenses associated with new solar and wind facilities placed in service in 2015 and 2016.

Depreciation and Amortization

First Quarter 2016 vs. First Quarter 2015
(change in millions)	(% change)
$14	23.7

In the first quarter 2016, depreciation and amortization was $73 million compared to $59 million for the corresponding period in 2015. The increase was primarily due to additional depreciation related to new solar and wind facilities placed in service in 2015 and 2016.

Interest Expense, net of Amounts Capitalized

First Quarter 2016 vs. First Quarter 2015
(change in millions)	(% change)
$(1)	(4.5)

In the first quarter 2016, interest expense, net of amounts capitalized was $21 million compared to $22 million for the corresponding period in 2015. The decrease was primarily due to a $9 million increase in capitalized interest associated with the construction of solar facilities, largely offset by an increase of $8 million in interest expense related to additional debt issued primarily to fund Southern Power's growth strategy and continuous construction program.

Income Taxes (Benefit)

First Quarter 2016 vs. First Quarter 2015
(change in millions)	(% change)
$(35)	N/M

N/M – Not meaningful

In the first quarter 2016, income tax benefit was $(23) million compared to an expense of $12 million for the corresponding period in 2015. The change was primarily due to a $28 million increase in federal income tax benefits from solar ITCs and wind PTCs in 2016 and a $7 million decrease in tax expense related to lower pre-tax earnings in 2016.

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 market areas; the successful remarketing of capacity as current contracts expire; and Southern Power's ability to execute its growth strategy, including successful additional investments in renewable and other energy projects, and to construct generating facilities, including the impact of federal ITCs. Demand for electricity is primarily driven by economic growth. The pace of economic growth and electricity demand may be affected by changes in regional and global economic conditions, which may impact future earnings.

Other factors that could influence future earnings include weather, demand, cost of generation from units within the power pool, and operational limitations. For additional information relating to these issues, see RISK FACTORS in

117

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Southern Power in Item 7 of the Form 10-K.

Power Sales Agreements

See BUSINESS – "The Southern Company System – Southern Power" in Item 1 of the Form 10-K for additional information regarding Southern Power's PPAs with investor-owned utilities, independent power purchasers, municipalities, electric cooperatives, and other load-serving entities.

At December 31, 2015, Southern Power's generation contract coverage ratio, which compares contracted capacity (MW) to available demonstrated capacity (MW), was an average of 75% for the next five years (through 2020) and 70% for the next 10 years (through 2025), with an average remaining contract duration of approximately 10 years.

Southern Power believes an investment contract ratio better identifies the value of assets covered since it represents the ratio of investment under contract to total investment using the respective generation facilities' net book value (or expected in-service value for facilities under construction or being acquired) as the investment amount. At March 31, 2016, the investment coverage ratio was 91% for the next five years (through 2020) and 90% for the next 10 years (through 2025), with an average remaining contract duration of approximately 18 years. At December 31, 2015, the investment coverage ratio would have been 91% for the next five years (through 2020) and 90% for the next 10 years (through 2025), with an average remaining contract duration of approximately 18 years.

Environmental Matters

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Southern Power in Item 7 of the Form 10-K for information on the development by federal and state environmental regulatory agencies of additional control strategies for emissions of air pollution from industrial sources, including electric generating facilities. Compliance with possible additional federal or state legislation or regulations related to global climate change, air quality, water quality, or other environmental and health concerns could also significantly affect Southern Power. While Southern Power's PPAs generally contain provisions that permit charging the counterparty with some of the new costs incurred as a result of changes in environmental laws and regulations, the full impact of any such regulatory or legislative changes cannot be determined at this time.

Acquisitions

During 2016, in accordance with its overall growth strategy, Southern Power acquired or contracted to acquire through its wholly-owned subsidiaries, Southern Renewable Partnerships, LLC or Southern Renewable Energy, Inc., the projects set forth in the following table. Acquisition-related costs were expensed as incurred and were not material. See Note (I) to the Condensed Financial Statements under "Southern Power" herein for additional information.

Project Facility	Approx. Nameplate Capacity	Location	Percentage Ownership		Expected/Actual COD	PPA Contract Period
	(MW)
SOLAR
Calipatria(a)	20	Imperial County, CA	90	%	February 11, 2016	20 years
East Pecos(b)	120	Pecos County, TX	100	%	Fourth quarter 2016	15 years
WIND
Grant Wind(c)	151	Grant County, OK	100	%	April 8, 2016	20 years
Passadumkeag(d)	40	Penobscot County, ME	100	%	Second quarter 2016	15 years

(a) Calipatria - On February 11, 2016, Southern Power, together with the minority owner, Turner Renewable Energy, LLC (TRE), which owns 10%, acquired all of the outstanding membership interests of Calipatria Solar, LLC.

118

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

(b) East Pecos - On March 4, 2016, Southern Power acquired all the outstanding membership interests of East Pecos Solar, LLC. Total construction costs, which include the acquisition price allocated to CWIP, are expected to be approximately $200 million to $220 million. The ultimate outcome of this matter cannot be determined at this time.

(c) Grant Wind - Subsequent to March 31, 2016, Southern Power acquired all the outstanding membership interests of Grant Wind, LLC.

(d) Passadumkeag - On March 11, 2016, Southern Power entered into an agreement to acquire all of the outstanding membership interests of Quantum Wind Acquisition I, LLC, which is expected to close in the second quarter 2016. The ultimate outcome of this matter cannot be determined at this time.

Construction Projects

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

During the first quarter 2016, in accordance with its overall growth strategy, Southern Power completed construction of and placed in service the Butler Solar Farm and Pawpaw solar facilities. In addition, Southern Power continued construction of the projects set forth in the table below. Through March 31, 2016, total costs of construction incurred for the projects below were $2.2 billion, of which $1.5 billion remains in CWIP. The ultimate outcome of these matters cannot be determined at this time.

Solar Facility	Approx. Nameplate Capacity	Location	Expected/Actual COD	PPA Contract Period	Estimated Construction Costs
	(MW)				(in millions)
Butler	103	Taylor County, GA	Fourth quarter 2016	30 years	$	220	-	230	(a)
Desert Stateline	299(b)	San Bernardino County, CA	Through third quarter 2016	20 years	$	1,200	-	1,300	(c)
Garland and Garland A(d)	205	Kern County, CA	Fourth quarter 2016 Third quarter 2016	15 years and 20 years	$	532	-	552	(e)
Roserock(d)	160	Pecos County, TX	Fourth quarter 2016	20 years	$	333	-	353	(e)
Sandhills	146	Taylor County, GA	Fourth quarter 2016	25 years	$	260	-	280
Tranquillity(d)	205	Fresno County, CA	Third quarter 2016	18 years	$	473	-	493	(f)

(a) Butler - Total estimated construction costs include the acquisition price of all outstanding membership interests of the related entity.

(b) Desert Stateline - The facility has a total of 299 MWs, of which 110 MWs were placed in service in the fourth quarter 2015 and 76 MWs were placed in service in the first quarter 2016. Subsequent to March 31, 2016, 38 MWs were placed in service. The remaining 75 MWs are expected to be placed in service by the end of the third quarter 2016.

(c) Desert Stateline - On March 29, 2016, Southern Power acquired an additional 15% interest in Desert Stateline. As a result, Southern Power and the class B member are entitled to 66% and 34%, respectively, of all cash distributions from Desert Stateline. In addition, Southern Power will continue to be entitled to substantially all of the federal tax benefits with respect to the transaction. Total estimated construction costs include the acquisition price allocated to CWIP; however, the allocation of the purchase price to individual assets has not been finalized.

(d) Southern Power owns 100% of the class A membership interests and a wholly-owned subsidiary of the seller owns 100% of the class B membership interests. Southern Power and the class B member are entitled to 51% and 49%, respectively, of all cash distributions from the project.

(e) Total estimated construction costs include the acquisition price allocated to CWIP. During the first quarter 2016, the allocation of the purchase price to individual assets was finalized with no changes.

(f) Total estimated construction costs include the acquisition price allocated to CWIP; however, the allocation of the purchase price to individual assets has not been finalized.

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

119

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Other Matters

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

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

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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

Recently Issued Accounting Standards

On February 25, 2016, the FASB issued ASU No. 2016-02, Leases(Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. Southern Power is currently evaluating the new standard and has not yet determined its ultimate impact.

FINANCIAL CONDITION AND LIQUIDITY

Overview

Southern Power's financial condition remained stable at March 31, 2016. Southern Power intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit agreements as needed to meet future capital and liquidity needs. See "Sources of Capital" herein for additional information on lines of credit.

Net cash used for operating activities totaled $110 million for the first three months of 2016, compared to $19 million for the first three months of 2015. The increase in cash used for operating activities was primarily due to an increase in income taxes paid. Net cash used for investing activities totaled $873 million for the first three months of 2016 primarily due to acquisitions and the construction of renewable facilities. Net cash provided from financing activities totaled $206 million for the first three months of 2016 primarily due to an increase in notes payable. Fluctuations in cash flow from financing activities vary from period to period based on capital needs and

120

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

the maturity or redemption of securities.

Significant balance sheet changes for the first three months of 2016 include a $398 million increase in CWIP due to continued construction of new solar facilities and a $412 million increase in plant in service, primarily due to solar facilities being placed in service. Other significant changes include a $777 million decrease in cash and cash equivalents and a $276 million increase in notes payable due to funding of acquisitions and construction projects, and income taxes. See FUTURE EARNINGS POTENTIAL – "Acquisitions" herein for additional information.

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, unrecognized tax benefits, and other purchase commitments. Approximately $400 million will be required to repay long-term debt due September 28, 2016. There are no other scheduled maturities of long-term debt through March 31, 2017. In addition, during the first quarter 2016, Southern Power entered into four new long-term service agreements (LTSA), which begin in 2020 and result in additional future commitments totaling approximately $627 million.

The construction program is subject to periodic review and revision. These amounts include estimates for potential plant acquisitions and new construction. In addition, the construction program includes capital improvements and work to be performed under LTSAs. Planned expenditures for plant acquisitions may vary materially due to market opportunities and Southern Power's ability to execute its growth strategy. Actual capital costs may vary from these estimates because of numerous factors such as: changes in business conditions; changes in the expected environmental compliance program; changes in environmental statutes and regulations; the outcome of any legal challenges to the environmental rules; changes in FERC rules and regulations; changes in load projections; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. See Note (I) to the Condensed Financial Statements herein for additional information.

Sources of Capital

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

As of March 31, 2016, Southern Power's current liabilities exceeded current assets by $977 million due to long-term debt maturing in 2016, the use of short-term debt as a funding source, and construction payables, as well as cash needs, which can fluctuate significantly due to the seasonality of the business and the stage of its acquisitions and construction projects. In 2016, Southern Power expects to utilize the capital markets, bank term loans, and commercial paper markets as the source of funds for the majority of its maturities.

As of March 31, 2016, Southern Power had cash and cash equivalents of approximately $53 million.

Other than borrowings pursuant to the Project Credit Facilities (defined below), Southern Power had no short-term borrowings during the first quarter 2016.

Company Facility

At March 31, 2016, Southern Power had a committed credit facility (Facility) of $600 million expiring in 2020, of which $560 million was unused. Southern Power's subsidiaries are not borrowers under the Facility.

121

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The Facility, as well as Southern Power's term loan agreement, contains a covenant that limits the ratio of debt to capitalization (as defined in the Facility) to a maximum of 65% and contains a cross default provision that is restricted only to indebtedness of Southern Power. For purposes of this definition, debt excludes any project debt incurred by certain subsidiaries of Southern Power to the extent such debt is non-recourse to Southern Power , and capitalization excludes the capital stock or other equity attributable to such subsidiary. Southern Power is currently in compliance with all covenants in the Facility.

Proceeds from the Facility may be used for working capital and general corporate purposes as well as liquidity support for Southern Power's commercial paper program. Subject to applicable market conditions, Southern Power expects to renew or replace the Facility, as needed, prior to expiration. In connection therewith, Southern Power may extend the maturity date and/or increase or decrease the lending commitment thereunder. 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, including maturing debt. Southern Power's subsidiaries are not borrowers under the commercial paper program.

Subsidiary Facilities

In connection with the construction of solar facilities by RE Tranquillity LLC, RE Roserock LLC, and RE Garland Holdings LLC, indirect subsidiaries of Southern Power, each subsidiary entered into separate credit agreements (Project Credit Facilities), which are non-recourse to Southern Power (other than the subsidiary party to the agreement). Each Project Credit Facility provides (a) a senior secured construction loan credit facility, (b) a senior secured bridge loan facility, and (c) a senior secured letter of credit facility that is secured by the membership interests of the respective project company. Proceeds from the Project Credit Facilities are being used to finance project costs related to the respective solar facilities currently under construction. Each Project Credit Facility is secured by the assets of the applicable project subsidiary and membership interests of the applicable project subsidiary. The table below summarizes each Project Credit Facility as of March 31, 2016.

Project	Maturity Date	Construction Loan Facility		Bridge Loan Facility		Total		Total Undrawn		Letter of Credit Facility		Total Undrawn
		(in millions)
Tranquillity	Earlier of COD or December 31, 2016	$	86	$	172	$	258	$	52	$	77	$	26
Roserock	Earlier of COD or November 30, 2016	63		180		243		121		23		16
Garland	Earlier of COD or November 30, 2016	86		308		394		309		49		32
Total		$	235	$	660	$	895	$	482	$	149	$	74

The Project Credit Facilities had total amounts outstanding as of March 31, 2016 of $413 million at a weighted average interest rate of 1.99%. For the three months ended March 31, 2016, these credit agreements had a maximum amount outstanding of $413 million, and an average amount outstanding of $260 million at a weighted average interest rate of 1.99%.

Southern Power believes the need for working capital can be adequately met by utilizing the commercial paper program, the Facility, bank term loans, and operating cash flows.

122

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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/or Baa2, or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, energy price risk management, and transmission.

The maximum potential collateral requirements under these contracts at March 31, 2016 were as follows:

Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB and/or Baa2	$	11
At BBB- and/or Baa3	$	350
Below BBB- and/or Baa3	$	1,063

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, a credit rating downgrade could impact the ability of Southern Power to access capital markets and would be likely to impact the cost at which it does so.

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 three months ended March 31, 2016, Southern Power's subsidiary repaid $3 million of long-term debt payable to TRE and borrowed $2 million due February 28, 2036 under promissory notes payable to TRE.

During the three months ended March 31, 2016, Southern Power's subsidiaries borrowed $276 million pursuant to the Project Credit Facilities at a weighted average interest rate of 1.99%. In addition, Southern Power's subsidiaries issued $8 million in letters of credit.

Subsequent to March 31, 2016, Southern Power's subsidiaries borrowed$187 million pursuant to the Project Credit Facilities at a weighted average interest rate of 1.93%.

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

123

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	125
B	Contingencies and Regulatory Matters	126
C	Fair Value Measurements	139
D	Stockholders' Equity	142
E	Financing	144
F	Retirement Benefits	146
G	Income Taxes	149
H	Derivatives	150
I	Acquisitions	161
J	Segment and Related Information	165

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, D, E, G, H, I

124

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, 2015 have been derived from the audited financial statements of each registrant. In the opinion of each registrant's management, the information regarding such registrant furnished herein reflects all adjustments, which, except as otherwise disclosed, are of a normal recurring nature, necessary to present fairly the results of operations for the periods ended March 31, 2016 and 2015. 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.

Recently Issued Accounting Standards

On February 25, 2016, the FASB issued ASU No. 2016-02, Leases(Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchangedand there is no change to the accounting for existing leveraged leases.ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The registrants are currently evaluating the new standard and have not yet determined its ultimate impact; however, adoption of ASU 2016-02 is expected to have a significant impact on Southern Company and the traditional operating companies' balance sheets.

On March 30, 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation(Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions. Most significantly, entities are required to recognize all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation as income tax expense or benefit in the income statement. Southern Company and the traditional operating companies currently recognize any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation in additional paid-in capital. ASU 2016-09 is effective for fiscal years

125

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

beginning after December 15, 2016, with early adoption permitted. Southern Company and the traditional operating companies are currently evaluating the new standard and have not yet determined its ultimate impact.

(B) CONTINGENCIES AND REGULATORY MATTERS

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

General Litigation Matters

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

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

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 affected sites. The traditional operating companies have each received authority from their respective state PSCs to recover approved environmental compliance costs through regulatory mechanisms. These rates are adjusted annually or as necessary within limits approved by the state PSCs.

Georgia Power's environmental remediation liability as of March 31, 2016 was $28 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 PRPs at the Brunswick site have completed a removal action as ordered by the EPA. Additional response actions at this site are anticipated. In September 2015, Georgia Power entered into an allocation agreement with another PRP, under which that PRP will be responsible (as between Georgia Power and that PRP) for paying and performing certain investigation, assessment, remediation, and other incidental activities at the Brunswick site. Assessment and potential cleanup of other sites are anticipated.

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.

Gulf Power's environmental remediation liability includes estimated costs of environmental remediation projects of approximately $46 million as of March 31, 2016. These estimated costs primarily relate to site closure criteria by the Florida Department of Environmental Protection (FDEP) for potential impacts to soil and groundwater from herbicide applications at Gulf Power substations. The schedule for completion of the remediation projects is subject to FDEP approval. The projects have been approved by the Florida PSC for recovery through Gulf Power's environmental cost recovery clause; therefore, these liabilities have no impact on net income.

126

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

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

FERC Matters

Municipal and Rural Associations Tariff

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

On March 31, 2016, Mississippi Power filed a request with the FERC for an increase in wholesale base revenues as agreed upon in the settlement agreement reached with its wholesale customers under the Municipal and Rural Associations (MRA) cost-based electric tariff. The settlement agreement provides that base rates under the MRA cost-based electric tariff will increase approximately $7 million annually, with revised rates effective for services rendered beginning May 1, 2016. The increase is primarily due to the Plant Daniel Units 1 and 2 scrubbers, which were placed in service in November 2015. Additionally, under the settlement agreement, the tariff customers agreed in principle to similar regulatory treatment for tariff ratemaking as the treatment approved for retail ratemaking under the Mississippi PSC order (In-Service Asset Rate Order). The Kemper IGCC regulatory treatment primarily includes (i) recovery of only the Kemper IGCC assets currently operational and providing service to customers and other related costs and (ii) removing all of the Kemper IGCC CWIP with a corresponding increase in accrual of AFUDC effective May 1, 2016. If approved by the FERC, the amount of base rate revenues to be recognized in 2016 is expected to be approximately $5 million. The additional resulting AFUDC is estimated to be approximately $6 million. The ultimate outcome of this matter cannot be determined at this time.

Fuel Cost Recovery

Mississippi Power has a wholesale MRA and a Market Based (MB) fuel cost recovery factor. At March 31, 2016, the amount of over-recovered wholesale MRA fuel costs included in the balance sheets was $25 million compared to $24 million at December 31, 2015. See Note 3 to the financial statements of Mississippi Power under "FERC Matters – Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information.

Market-Based Rate Authority

The traditional operating companies and Southern Power have authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional operating companies and Southern Power filed a triennial market power analysis in 2014, which included continued reliance on the energy auction as tailored mitigation. In April 2015, the FERC issued an order finding that the traditional operating companies' and Southern Power's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional operating companies and in some adjacent areas. The FERC directed the traditional operating companies and Southern Power to show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional operating companies and Southern Power filed a request for rehearing in May 2015 and in June 2015 filed their response with the FERC. The ultimate outcome of this matter cannot be determined at this time.

127

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 balance of each regulatory clause recovery on the balance sheet follows:

Regulatory Clause	Balance Sheet Line Item	March 31, 2016		December 31, 2015
		(in millions)
Rate CNP Compliance	Under recovered regulatory clause revenues, current	$	22	$	43
Rate CNP PPA	Deferred under recovered regulatory clause revenues	105		99
Retail Energy Cost Recovery	Other regulatory liabilities, current	173		238
	Deferred over recovered regulatory clause revenues	64		—
Natural Disaster Reserve	Other regulatory liabilities, deferred	74		75

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.

Georgia Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Georgia PSC. Georgia Power currently recovers its costs from the regulated retail business through the 2013 ARP, which includes traditional base tariff rates, Demand-Side Management tariffs, Environmental Compliance Cost Recovery tariffs, and Municipal Franchise Fee tariffs. In addition, financing costs related to the construction of Plant Vogtle Units 3 and 4 are being collected through the NCCR tariff and fuel costs are collected through separate fuel cost recovery tariffs. See "Fuel Cost Recovery" below and Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Nuclear Construction" and Southern Company under "Retail Regulatory Matters – Georgia Power – Fuel Cost Recovery" and " – Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding fuel cost recovery and the NCCR tariff, respectively.

Pursuant to the terms and conditions of a settlement agreement related to Southern Company's proposed acquisition of AGL Resources approved by the Georgia PSC on April 14, 2016, Georgia Power's 2013 ARP will continue in effect until December 31, 2019, and Georgia Power will be required to file its next base rate case by July 1, 2019. Furthermore, through December 31, 2019, Georgia Power and Atlanta Gas Light Company (collectively, Utilities) will retain the merger savings, net of transition costs, as defined in the settlement agreement; through December 31, 2022, net merger savings will be shared on a 60/40 basis between customers and the Utilities; thereafter, all merger savings will be retained by customers. See Note (I) under "Southern Company – Proposed Merger with AGL Resources" for additional information regarding the Merger.

Fuel Cost Recovery

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

As of March 31, 2016 and December 31, 2015, Georgia Power's over recovered fuel balance totaled $177 million and $116 million, respectively, and is included in current liabilities and other deferred liabilities on Southern Company's and Georgia Power's Condensed Balance Sheets herein. On April 14, 2016, Georgia Power filed a

128

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

request with the Georgia PSC to decrease fuel rates by 15% effective June 1, 2016, which is expected to reduce annual billings by approximately $313 million. Georgia Power is currently scheduled to file its next fuel case by February 28, 2017. The ultimate outcome of this matter cannot be determined at this time.

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 or Georgia Power's revenues or net income, but will affect cash flow.

Nuclear Construction

See Note 3 to the financial statements of Southern Company and Georgia Power under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" and "Retail Regulatory Matters – Nuclear Construction," respectively, in Item 8 of the Form 10-K for additional information regarding Georgia Power's construction of Plant Vogtle Units 3 and 4, Vogtle Construction Monitoring (VCM) reports, the NCCR tariff, the Vogtle Construction Litigation (as defined below), and the Contractor Settlement Agreement (as defined below).

In 2008, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into an agreement with 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).

Under the terms of the Vogtle 3 and 4 Agreement, the Vogtle Owners agreed to pay a purchase price that is subject to certain price escalations and adjustments, including fixed escalation amounts and index-based adjustments, as well as adjustments for change orders, and performance bonuses for early completion and unit performance. The Vogtle 3 and 4 Agreement also provides for liquidated damages upon the Contractor's failure to fulfill the schedule and performance guarantees, subject to a cap. In addition, the Vogtle 3 and 4 Agreement provides for limited cost sharing by the Vogtle Owners for Contractor costs under certain conditions (which have not occurred), with maximum additional capital costs under this provision attributable to Georgia Power (based on Georgia Power's ownership interest) of approximately $114 million. Each Vogtle Owner is severally (and not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to the Contractor under the Vogtle 3 and 4 Agreement. Georgia Power's proportionate share is 45.7%.

On December 31, 2015, Westinghouse acquired Stone & Webster, Inc. from Chicago Bridge & Iron Company, N.V. (CB&I) and changed the name of Stone & Webster, Inc. to WECTEC Global Project Services Inc. (WECTEC). Certain obligations of Westinghouse and WECTEC under the Vogtle 3 and 4 Agreement were originally guaranteed by Toshiba Corporation (Westinghouse's parent company) and The Shaw Group Inc. (which is now a subsidiary of CB&I), respectively. On March 9, 2016, in connection with Westinghouse's acquisition of WECTEC and pursuant to the settlement agreement described below, the guarantee of The Shaw Group Inc. was terminated. The guarantee of Toshiba Corporation remains in place. 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. Additionally, as a result of credit rating downgrades of Toshiba Corporation, Westinghouse provided the Vogtle Owners with letters of credit in an aggregate amount of $920 million in accordance with, and subject to adjustment under, the terms of the Vogtle 3 and 4 Agreement.

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 Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4. 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 construction capital costs to be borne by Georgia Power increase by 5% above the certified cost 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. In February 2013, Georgia Power 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

129

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

billion and to extend the estimated in-service dates to the fourth quarter 2017 (from April 2016) and the fourth quarter 2018 (from April 2017) for Plant Vogtle Units 3 and 4, respectively. In October 2013, the Georgia PSC approved a stipulation (2013 Stipulation) between Georgia Power and the Georgia PSC Staff (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.

On April 15, 2015, the Georgia PSC issued a procedural order in connection with the twelfth VCM report, which included a requested amendment (Requested Amendment) to the Plant Vogtle Units 3 and 4 certificate to reflect the Contractor's revised forecast for completion of Plant Vogtle Units 3 and 4 (second quarter of 2019 and second quarter of 2020, respectively) as well as additional estimated Vogtle Owner's costs, of approximately $10 million per month, including property taxes, oversight costs, compliance costs, and other operational readiness costs to include the estimated Vogtle Owner's costs associated with the proposed 18-month Contractor delay and to increase the estimated total in-service capital cost of Plant Vogtle Units 3 and 4 to $5.0 billion. Pursuant to the Georgia PSC's procedural order, the Georgia PSC deemed the Requested Amendment unnecessary and withdrawn until the completion of construction of Plant Vogtle Unit 3 consistent with the 2013 Stipulation. The Georgia PSC recognized that the certified cost and the 2013 Stipulation do not constitute a cost recovery cap. In accordance with the Georgia Integrated Resource Planning Act, any costs incurred by Georgia Power in excess of the certified amount will be included in rate base, provided Georgia Power shows the costs to be reasonable and prudent. Financing costs up to the certified amount will be collected through the NCCR tariff until the units are placed in service and contemplated in a general base rate case, while financing costs on any construction-related costs in excess of the $4.4 billion certified amount are expected to be recovered through AFUDC.

On December 31, 2015, Westinghouse and the Vogtle Owners entered into a definitive settlement agreement (Contractor Settlement Agreement) to resolve disputes between the Vogtle Owners and the Contractor under the Vogtle 3 and 4 Agreement, including litigation that was pending in the U.S. District Court for the Southern District of Georgia (Vogtle Construction Litigation). Effective December 31, 2015, Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the Contractor entered into an amendment to the Vogtle 3 and 4 Agreement to implement the Contractor Settlement Agreement. The Contractor Settlement Agreement and the related amendment to the Vogtle 3 and 4 Agreement (i) restrict the Contractor's ability to seek further increases in the contract price by clarifying and limiting the circumstances that constitute nuclear regulatory changes in law; (ii) provide for enhanced dispute resolution procedures; (iii) revise the guaranteed substantial completion dates to match the current estimated in-service dates of June 30, 2019 for Unit 3 and June 30, 2020 for Unit 4; (iv) provide that delay liquidated damages will commence from the current estimated nuclear fuel loading date for each unit, which is December 31, 2018 for Unit 3 and December 31, 2019 for Unit 4; and (v) provide that Georgia Power, based on its ownership interest, will pay to the Contractor and capitalize to the project cost approximately $350 million, of which approximately $241 million had been paid as of March 31, 2016. In addition, the Contractor Settlement Agreement provides for the resolution of other open existing items relating to the scope of the project under the Vogtle 3 and 4 Agreement, including cyber security, for which costs were reflected in Georgia Power's previously disclosed in-service cost estimate. Further, as part of the settlement and Westinghouse's acquisition of WECTEC: (i) Westinghouse engaged Fluor Enterprises, Inc., a subsidiary of Fluor Corporation, as a new construction subcontractor; and (ii) the Vogtle Owners, CB&I, and The Shaw Group Inc. entered into mutual releases of any and all claims arising out of events or circumstances in connection with the construction of Plant Vogtle Units 3 and 4 that occurred on or before the date of the Contractor Settlement Agreement. On January 5, 2016, the Vogtle Construction Litigation was dismissed with prejudice.

On January 21, 2016, Georgia Power submitted the Contractor Settlement Agreement and the related amendment to the Vogtle 3 and 4 Agreement to the Georgia PSC for its review. In accordance with the Georgia PSC's subsequent order, on April 5, 2016, Georgia Power filed supplemental information in support of the Contractor Settlement Agreement and Georgia Power's position that all construction costs to date have been prudently incurred and that the current estimated in-service capital cost and schedule are reasonable. The Staff will conduct a review of all costs incurred related to Plant Vogtle Units 3 and 4, the schedule for completion of Plant Vogtle Units 3 and 4, and the

130

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Contractor Settlement Agreement and the Staff is authorized to engage in related settlement discussions with Georgia Power and any intervenors.

The order provides that the Staff is required to report to the Georgia PSC by October 19, 2016 with respect to the status of its review and any settlement-related negotiations. If a settlement with the Staff is reached with respect to costs of Plant Vogtle Units 3 and 4, the Georgia PSC will then conduct a hearing to consider whether to approve that settlement. If a settlement with the Staff is not reached, the Georgia PSC will determine how to proceed, including (i) modifying the 2013 Stipulation, (ii) directing Georgia Power to file a request for an amendment to the certificate for Plant Vogtle Units 3 and 4, (iii) issuing a scheduling order to address remaining disputed issues, or (iv) taking any other option within its authority.

The Georgia PSC has approved thirteen VCM reports covering the periods through June 30, 2015, including construction capital costs incurred, which through that date totaled $3.1 billion. On February 26, 2016, Georgia Power filed its fourteenth VCM report with the Georgia PSC covering the period from July 1 through December 31, 2015. The fourteenth VCM report does not include a requested amendment to the certified cost of Plant Vogtle Units 3 and 4. Georgia Power is requesting approval of $160 million of construction capital costs incurred during that period. Georgia Power anticipates to incur average financing costs of approximately $27 million per month from January 2016 until Plant Vogtle Units 3 and 4 are placed in service. The updated in-service capital cost forecast is $5.44 billion and includes costs related to the Contractor Settlement Agreement. Estimated financing costs during the construction period total approximately $2.4 billion. Georgia Power's CWIP balance for Plant Vogtle Units 3 and 4 was approximately $3.7 billion as of March 31, 2016.

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 may arise as construction proceeds. Processes are in place that are designed to assure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating licenses, 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 may 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 challenges with Contractor performance including fabrication, assembly, delivery, and installation of the shield building and structural modules, delays in the receipt of the remaining permits necessary for the operation of Plant Vogtle Units 3 and 4, or other issues could arise and may further impact project schedule and cost. In addition, the IRS allocated production tax credits to each of Plant Vogtle Units 3 and 4, which require the applicable unit to be placed in service before 2021.

Future claims by the Contractor or Georgia Power (on behalf of the Vogtle Owners) could arise throughout construction. These claims may be resolved through formal and informal dispute resolution procedures under the Vogtle 3 and 4 Agreement and, under the enhanced dispute resolution procedures, may be resolved through litigation after the completion of nuclear fuel load for both units.

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

Gulf Power

Retail Base Rate Case

See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Retail Base Rate Case" in Item 8 of the Form 10-K for additional information.

In 2013, the Florida PSC approved a settlement agreement providing that Gulf Power may reduce depreciation and record a regulatory asset up to $62.5 million between January 2014 and June 2017. In any given month, such depreciation reduction may not exceed the amount necessary for the retail ROE, as reported to the Florida PSC

131

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

monthly, to reach the midpoint of the authorized retail ROE range then in effect. For 2014, 2015, and the first three months of 2016, Gulf Power recognized reductions in depreciation of $8.4 million, $20.1 million, and $5.6 million, respectively.

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 balance of each regulatory clause recovery on the balance sheet follows:

Regulatory Clause	Balance Sheet Location	March 31, 2016		December 31, 2015
		(in millions)
Fuel Cost Recovery	Other regulatory liabilities, current	$	20	$	18
Purchased Power Capacity Recovery	Under recovered regulatory clause revenues	4		1
Environmental Cost Recovery	Under recovered regulatory clause revenues	17		19
Energy Conservation Cost Recovery	Other regulatory liabilities, current	2		4

Mississippi Power

Performance Evaluation Plan

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

On April 1, 2016, Mississippi Power submitted its annual PEP lookback filing for 2015, which reflected the need for a $5 million surcharge to be recovered from customers. The filing has been suspended for review by the Mississippi PSC. The ultimate outcome of this matter 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 retail fuel cost recovery.

At March 31, 2016, the amount of over-recovered retail fuel costs included on Mississippi Power's Condensed Balance Sheet herein was $80 million compared to over-recovered retail fuel costs of $71 million at December 31, 2015.

The Mississippi PSC conditionally approved a decrease of $120 million annually in fuel cost recovery rates on January 5, 2016, effective with the first billing cycle of February. As required by the order, on February 1, 2016, Mississippi Power submitted updated natural gas price forecasts and resulting fuel factors to the Mississippi PSC. If approved by the Mississippi PSC, the updated forecast would decrease fuel cost recovery rates by an additional $36 million annually. The ultimate outcome of this matter cannot be determined at this time.

Integrated Coal Gasification Combined Cycle

See Note 3 to the financial statements of Southern Company and Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K for information regarding Mississippi Power's construction of the Kemper IGCC.

Kemper IGCC Overview

Construction of Mississippi Power's Kemper IGCC is nearing completion and start-up activities will continue until the Kemper IGCC is placed in service. The Kemper IGCC will utilize an IGCC technology with an output capacity

132

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

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

Kemper IGCC Schedule and Cost Estimate

In 2012, the Mississippi PSC issued the 2012 MPSC CPCN Order, a detailed order confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing the acquisition, construction, and operation of the Kemper IGCC. The certificated cost estimate of the Kemper IGCC included in the 2012 MPSC CPCN Order was $2.4 billion, net of $245 million of grants awarded to the Kemper IGCC project by the DOE under the Clean Coal Power Initiative Round 2 (Initial DOE Grants) and excluding the cost of the lignite mine and equipment, the cost of the CO₂ pipeline facilities, and AFUDC related to the Kemper IGCC. The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, with recovery of prudently-incurred costs subject to approval by the Mississippi PSC. The Kemper IGCC was originally projected to be placed in service in May 2014. Mississippi Power placed the combined cycle and the associated common facilities portion of the Kemper IGCC in service using natural gas in August 2014 and currently expects to place the remainder of the Kemper IGCC, including the gasifier and the gas clean-up facilities, in service during the third quarter 2016.

133

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Recovery of the costs subject to the cost cap and the cost of the lignite mine and equipment, the cost of the CO₂ pipeline facilities, AFUDC, and certain general exceptions, including change of law, force majeure, and beneficial capital (which exists when Mississippi Power demonstrates that the purpose and effect of the construction cost increase is to produce efficiencies that will result in a neutral or favorable effect on customers relative to the original proposal for the CPCN) (Cost Cap Exceptions) remains subject to review and approval by the Mississippi PSC. Mississippi Power's Kemper IGCC 2010 project estimate, current cost estimate (which includes the impacts of the Mississippi Supreme Court's (Court) decision discussed herein under "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order"), and actual costs incurred as of March 31, 2016, are as follows:

Cost Category	2010 Project Estimate(f)		Current Cost Estimate(a)			Actual Costs
	(in billions)
Plant Subject to Cost Cap(b)(g)	$	2.40	$	5.35		$	4.99
Lignite Mine and Equipment	0.21		0.23			0.23
CO2 Pipeline Facilities	0.14		0.11			0.12
AFUDC(c)	0.17		0.71			0.62
Combined Cycle and Related Assets Placed in Service – Incremental(d)(g)	—		0.02			0.01
General Exceptions	0.05		0.10			0.09
Deferred Costs(e)(g)	—		0.20			0.18
Additional DOE Grants(h)	—		(0.14		)	—
Total Kemper IGCC	$	2.97	$	6.58		$	6.24

(a) Amounts in the Current Cost Estimate reflect estimated costs through September 30, 2016.

(b) The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, net of the Initial DOE Grants and excluding the Cost Cap Exceptions. The Current Cost Estimate and the Actual Costs include non-incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service in August 2014 that are subject to the $2.88 billion cost cap and exclude post-in-service costs for the lignite mine. See "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" herein for additional information. The Current Cost Estimate and the Actual Costs reflect 100% of the costs of the Kemper IGCC. See note (g) for additional information.

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

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

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

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

(g) Beginning in the third quarter 2015, certain costs, including debt carrying costs (associated with assets placed in service and other non-CWIP accounts), that previously were deferred as regulatory assets are now being recognized through income; however, such costs continue to be included in the Current Cost Estimate and the Actual Costs at March 31, 2016.

(h) On April 8, 2016, Mississippi Power received approximately $137 million in additional grants from the DOE for the Kemper IGCC, which are expected to be used to reduce future rate impacts for customers.

Of the total costs, including post-in-service costs for the lignite mine, incurred as of March 31, 2016, $3.61 billion was included in property, plant, and equipment (which is net of the Initial DOE Grants and estimated probable losses of $2.47 billion), $6 million in other property and investments, $75 million in fossil fuel stock, $45 million in materials and supplies, $22 million in other regulatory assets, current, $196 million in other regulatory assets, deferred, $1 million in other current assets, and $11 million in other deferred charges and assets in the balance sheet.

134

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Mississippi Power does not intend to seek rate recovery for any costs related to the construction of the Kemper IGCC that exceed the $2.88 billion cost cap, net of the Initial DOE Grants and excluding the Cost Cap Exceptions. Mississippi Power recorded pre-tax charges to income for revisions to the cost estimate above the cost cap of $53 million ($33 million after tax) in the first quarter 2016. Since 2012, in the aggregate, Mississippi Power has incurred charges of $2.47 billion ($1.52 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through March 31, 2016. The increase to the cost estimate in the first quarter 2016 primarily reflects costs for the extension of the Kemper IGCC's projected in-service date through September 30, 2016, and increased efforts related to operational readiness and challenges in start-up and commissioning activities which includes the cost of repairs and modifications to the refractory lining inside the gasifiers. Any extension of the in-service date beyond September 30, 2016 is currently estimated to result in additional base costs of approximately $25 million to $35 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. However, additional costs may be required for remediation of any further equipment and/or design issues identified. Any extension of the in-service date with respect to the Kemper IGCC beyond September 30, 2016 would also increase costs for the Cost Cap Exceptions, which are not subject to the $2.88 billion cost cap established by the Mississippi PSC. These costs include AFUDC, which is currently estimated to total approximately $14 million per month, as well as carrying costs and operating expenses on Kemper IGCC assets placed in service and consulting and legal fees of approximately $2 million per month. For additional information, see "2015 Rate Case" herein.

Mississippi Power's analysis of the time needed to complete the start-up and commissioning activities for the Kemper IGCC will continue until the remaining Kemper IGCC assets are placed in service. 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 operating or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities for this first-of-a-kind technology (including major equipment failure and system integration), and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC). In subsequent periods, any further changes in the estimated costs to complete construction and start-up of the Kemper IGCC subject to the $2.88 billion cost cap, net of the Initial DOE Grants and excluding the Cost Cap Exceptions, will be reflected in Southern Company's and Mississippi Power's statements of income and these changes could be material.

Rate Recovery of Kemper IGCC Costs

See "FERC Matters" herein for additional information regarding Mississippi Power's MRA cost based tariff relating to recovery of a portion of the Kemper IGCC costs from Mississippi Power's wholesale customers. Rate recovery of the retail portion of the Kemper IGCC is subject to the jurisdiction of the Mississippi PSC. See Note (G) under "Unrecognized Tax Benefits – Section 174 Research and Experimental Deduction" for additional tax information related to the Kemper IGCC.

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 future proceedings related to the operation of the Kemper

135

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

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 MPSC Rate Order

In January 2013, Mississippi Power entered into a settlement agreement with the Mississippi PSC that was intended to establish the process for resolving matters regarding cost recovery related to the Kemper IGCC (2013 Settlement Agreement). Under the 2013 Settlement Agreement, Mississippi Power agreed to limit the portion of prudently-incurred Kemper IGCC costs to be included in retail rate base to the $2.4 billion certificated cost estimate, plus the Cost Cap Exceptions, but excluding AFUDC, and any other costs permitted or determined to be excluded from the $2.88 billion cost cap by the Mississippi PSC. In March 2013, the Mississippi PSC issued a rate order approving retail rate increases of 15% effective March 19, 2013 and 3% effective January 1, 2014, which collectively were designed to collect $156 million annually beginning in 2014 (2013 MPSC Rate Order) to be used to mitigate customer rate impacts after the Kemper IGCC is placed in service, based on a mirror CWIP methodology (Mirror CWIP rate).

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. 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.

On February 12, 2015, the Court reversed the 2013 MPSC Rate Order based on, among other things, its findings that (1) the Mirror CWIP rate treatment was not provided for under the Baseload Act and (2) the Mississippi PSC should have determined the prudence of Kemper IGCC costs before approving rate recovery through the 2013 MPSC Rate Order. The Court also found the 2013 Settlement Agreement unenforceable due to a lack of public notice for the related proceedings. On July 7, 2015, the Mississippi PSC ordered that the Mirror CWIP rate be terminated effective July 20, 2015 and required the fourth quarter 2015 refund of the $342 million collected under the 2013 MPSC Rate Order, along with associated carrying costs of $29 million. The Court's decision did not impact the 2012 MPSC CPCN Order or the February 2013 legislation described below.

2015 Rate Case

As a result of the 2015 Court decision, on July 10, 2015, Mississippi Power filed a supplemental filing including a request for interim rates (Supplemental Notice) with the Mississippi PSC which presented an alternative rate proposal (In-Service Asset Proposal) designed to recover Mississippi Power's costs associated with the Kemper IGCC assets that are commercially operational and currently providing service to customers (the transmission facilities, combined cycle, natural gas pipeline, and water pipeline) and other related costs. On August 13, 2015, the Mississippi PSC approved the implementation of the requested interim rates designed to collect approximately $159 million annually effective with the first billing cycle in September 2015, subject to refund and certain other conditions.

On December 3, 2015, the Mississippi PSC issued the In-Service Asset Rate Order adopting in full a stipulation entered into between Mississippi Power and the Mississippi Public Utilities Staff (MPUS) regarding the In-Service Asset Proposal. The In-Service Asset Rate Order provided for retail rate recovery of an annual revenue requirement of approximately $126 million, based on Mississippi Power's actual average capital structure, with a maximum common equity percentage of 49.733%, a 9.225% return on common equity, and actual embedded interest costs. The In-Service Asset Rate Order also included a prudence finding of all costs in the stipulated revenue requirement calculation for the in-service assets. The stipulated revenue requirement excluded the costs of the Kemper IGCC related to the 15% undivided interest that was previously projected to be purchased by SMEPA. Mississippi Power continues to evaluate its alternatives with respect to its investment and related costs associated with the 15% undivided interest.

136

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

With implementation of the new rate on December 17, 2015, the interim rates were terminated and, in March 2016, Mississippi Power completed customer refunds of approximately $11 million for the difference between the interim rates collected and the permanent rates.

Pursuant to the In-Service Asset Rate Order, Mississippi Power is required to file a subsequent rate request within 18 months. As part of the filing, Mississippi Power expects to request recovery of certain costs that the Mississippi PSC had excluded from the revenue requirement calculation.

On February 25, 2016, Greenleaf CO2 Solutions, LLC filed a notice of appeal of the In-Service Asset Rate Order with the Court. On May 5, 2016, the Court dismissed the appeal.

Legislation to authorize a multi-year rate plan and legislation to provide for alternate financing through securitization of up to $1.0 billion of prudently-incurred costs was enacted into law in 2013. Mississippi Power expects to securitize prudently-incurred qualifying facility costs in excess of the certificated cost estimate of $2.4 billion. Qualifying facility costs include, but are not limited to, pre-construction costs, construction costs, regulatory costs, and accrued AFUDC. The Court's decision regarding the 2013 MPSC Rate Order did not impact Mississippi Power's ability to utilize alternate financing through securitization or the February 2013 legislation.

Mississippi Power expects to seek additional rate relief to address recovery of the remaining Kemper IGCC assets. In addition to current estimated costs at March 31, 2016 of $6.58 billion, Mississippi Power anticipates that it will incur additional costs after the Kemper IGCC in-service date until the Kemper IGCC cost recovery approach is finalized. These costs include, but are not limited to, regulatory costs and additional carrying costs which could be material. Recovery of these costs would be subject to approval by the Mississippi PSC.

Regulatory Assets and Liabilities

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

In August 2014, Mississippi Power requested confirmation by the Mississippi PSC of Mississippi Power's authority to defer all operating expenses associated with the operation of the combined cycle subject to review of such costs by the Mississippi PSC. In addition, Mississippi Power is authorized to accrue carrying costs on the unamortized balance of such regulatory assets at a rate and in a manner to be determined by the Mississippi PSC in future cost recovery mechanism proceedings. Beginning in the third quarter 2015, in connection with the implementation of interim rates, Mississippi Power began expensing certain ongoing project costs and certain debt carrying costs (associated with assets placed in service and other non-CWIP accounts) that previously were deferred as regulatory assets and began amortizing certain regulatory assets associated with assets placed in service and consulting and legal fees. The amortization periods for these regulatory assets vary from two years to 10 years as set forth in the In-Service Asset Rate Order. As of March 31, 2016, the balance associated with these regulatory assets was $120 million, of which $22 million is included in current assets. Other regulatory assets associated with the remainder of the Kemper IGCC totaled $98 million as of March 31, 2016. The amortization period for these assets is expected to be determined by the Mississippi PSC in future rate proceedings following completion of construction and start-up of the Kemper IGCC and related prudence reviews.

See "2013 MPSC Rate Order" herein for information related to the July 7, 2015 Mississippi PSC order terminating the Mirror CWIP rate and requiring refund of collections under Mirror CWIP.

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

The In-Service Asset Rate Order requires Mississippi Power to submit an annual true-up calculation of its actual cost of capital, compared to the stipulated total cost of capital, with the first occurring as of May 31, 2016. As of

137

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

March 31, 2016, Mississippi Power recorded a related regulatory liability of approximately $3 million. See "2015 Rate Case" herein for additional information.

Lignite Mine and CO₂ Pipeline Facilities

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

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

In addition, Mississippi Power has constructed and will operate the CO₂ pipeline for the planned transport of captured CO₂ for use in enhanced oil recovery. Mississippi Power has entered into agreements with Denbury Onshore (Denbury), a subsidiary of Denbury Resources Inc., and Treetop Midstream Services, LLC (Treetop), an affiliate of Tellus Operating Group, LLC and a subsidiary of Tengrys, LLC, pursuant to which Denbury will purchase 70% of the CO₂ captured from the Kemper IGCC and Treetop will purchase 30% of the CO₂ captured from the Kemper IGCC. The agreements with Denbury and Treetop provide Denbury and Treetop with termination rights as Mississippi Power has not satisfied its contractual obligation to deliver captured CO₂ by May 11, 2015. Since May 11, 2015, Mississippi Power has been engaged in ongoing discussions with its off-takers regarding the status of the CO₂ delivery schedule as well as other issues related to the CO₂ agreements. As a result of discussions with Treetop, on August 3, 2015, Mississippi Power agreed to amend certain provisions of their agreement that do not affect pricing or minimum purchase quantities. Potential requirements imposed on CO₂ off-takers under the Clean Power Plan (if ultimately enacted in its current form, pending resolution of litigation) and the potential adverse financial impact of low oil prices on the off-takers increase the risk that the CO₂ contracts may be terminated or materially modified. Any termination or material modification of these agreements could result in a material reduction in Mississippi Power's revenues to the extent Mississippi Power is not able to enter into other similar contractual arrangements. Additionally, if the contracts remain in place, sustained oil price reductions could result in significantly lower revenues than Mississippi Power forecasted to be available to offset customer rate impacts, which could have a material impact on Mississippi Power's financial statements.

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

Civil Lawsuit

On April 26, 2016, a complaint against Mississippi Power was filed in Harrison County Circuit Court by Biloxi Freezing & Processing Inc., Gulfside Casino Partnership, and John Carlton Dean. The plaintiffs allege that Mississippi Power violated the Mississippi Unfair Trade Practices Act and concealed, falsely represented, and failed to fully disclose important facts concerning the cost and schedule of the Kemper IGCC and that Mississippi Power's alleged breaches interfered with and destroyed economically advantageous relationships between the plaintiffs and their current and prospective business associates. The plaintiffs seek unspecified actual damages and punitive damages as well as attorney's fees, costs, and interest. The plaintiffs also seek an injunction to prevent any Kemper IGCC costs from being charged to customers through electric rates. Mississippi Power believes this legal challenge has no merit; however, an adverse outcome in this proceeding could impact Southern Company's results of operations, financial condition, and liquidity and could have a material impact on Mississippi Power's results of operations, financial condition, and liquidity. Mississippi Power will vigorously defend the matter, and the final outcome of this matter cannot be determined at this time.

138

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

(C) FAIR VALUE MEASUREMENTS

As of March 31, 2016, assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows:

	Fair Value Measurements Using
As of March 31, 2016:	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Net Asset Value as a Practical Expedient (NAV)		Total
	(in millions)
Southern Company
Assets:
Energy-related derivatives	$	—	$	12	$	—	$	—	$	12
Interest rate derivatives	—		33		—		—		33
Nuclear decommissioning trusts(a)	624		898		—		16		1,538
Cash equivalents	503		—		—		—		503
Other investments	9		—		1		—		10
Total	$	1,136	$	943	$	1	$	16	$	2,096
Liabilities:
Energy-related derivatives	$	—	$	201	$	—	$	—	$	201
Interest rate derivatives	—		193		—		—		193
Total	$	—	$	394	$	—	$	—	$	394
Alabama Power
Assets:
Energy-related derivatives	$	—	$	3	$	—	$	—	$	3
Nuclear decommissioning trusts(b)
Domestic equity	365		67		—		—		432
Foreign equity	46		48		—		—		94
U.S. Treasury and government agency securities	—		25		—		—		25
Corporate bonds	11		137		—		—		148
Mortgage and asset backed securities	—		21		—		—		21
Private Equity	—		—		—		16		16
Other	—		9		—		—		9
Cash equivalents	321		—		—		—		321
Total	$	743	$	310	$	—	$	16	$	1,069
Liabilities:
Energy-related derivatives	$	—	$	49	$	—	$	—	$	49

139

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

	Fair Value Measurements Using
As of March 31, 2016:	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Net Asset Value as a Practical Expedient (NAV)		Total
	(in millions)
Georgia Power
Assets:
Energy-related derivatives	$	—	$	4	$	—	$	—	$	4
Interest rate derivatives	—		14		—		—		14
Nuclear decommissioning trusts(b) (c)
Domestic equity	180		1		—		—		181
Foreign equity	—		115		—		—		115
U.S. Treasury and government agency securities	—		111		—		—		111
Municipal bonds	—		66		—		—		66
Corporate bonds	—		146		—		—		146
Mortgage and asset backed securities	—		145		—		—		145
Other	22		7		—		—		29
Cash equivalents	57		—		—		—		57
Total	$	259	$	609	$	—	$	—	$	868
Liabilities:
Energy-related derivatives	$	—	$	11	$	—	$	—	$	11
Gulf Power
Assets:
Cash equivalents	$	20	$	—	$	—	$	—	$	20
Liabilities:
Energy-related derivatives	$	—	$	94	$	—	$	—	$	94
Interest rate derivatives	—		5		—		—		5
Total	$	—	$	99	$	—	$	—	$	99
Mississippi Power
Assets:
Cash equivalents	$	24	$	—	$	—	$	—	$	24
Liabilities:
Energy-related derivatives	$	—	$	44	$	—	$	—	$	44
Southern Power
Assets:
Energy-related derivatives	$	—	$	5	$	—	$	—	$	5
Interest rate derivatives	—		1		—		—		1
Cash equivalents	39		—		—		—		39
Total	$	39	$	6	$	—	$	—	$	45
Liabilities:
Energy-related derivatives	$	—	$	3	$	—	$	—	$	3

140

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

(a) For additional detail, see the nuclear decommissioning trusts sections for Alabama Power and Georgia Power in this table.

(b) Excludes receivables related to investment income, pending investment sales, payables related to pending investment purchases, and currencies.

(c) Includes the investment securities pledged to creditors and collateral received and excludes payables related to the securities lending program. As of March 31, 2016, approximately $58 million of the fair market value of Georgia Power's nuclear decommissioning trust funds' securities were on loan to creditors under the funds' managers' securities lending program.

Southern Company, Alabama Power, and Georgia Power continue to elect the option to fair value investment securities held in the nuclear decommissioning trust funds. For the three months ended March 31, 2016 and March 31, 2015, the change in fair value of the funds, including reinvested interest and dividends and excluding the funds' expenses, increased by $20 million and $33 million, respectively, at Southern Company. For the three months ended March 31, 2016 and March 31, 2015, Alabama Power recorded an increase in fair value of $11 million and $15 million, respectively, as an increase in regulatory liabilities related to its asset retirement obligations. For the three months ended March 31, 2016 and March 31, 2015, Georgia Power recorded an increase in fair value of $9 million and $18 million, respectively, as a reduction of its regulatory asset related to its asset retirement obligations.

Valuation Methodologies

The energy-related derivatives primarily consist of over-the-counter financial products for natural gas and physical power products, including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and overnight index swap interest rates. Interest rate derivatives are also standard over-the-counter products that are valued using observable market data and assumptions commonly used by market participants. The fair value of interest rate derivatives reflect the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future interest rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk, and occasionally, implied volatility of interest rate options. The interest rate derivatives are categorized as Level 2 under Fair Value Measurements as these inputs are based on observable data and valuations of similar instruments. See Note (H) for additional information on how these derivatives are used.

The NRC requires licensees of commissioned nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. For fair value measurements of the investments within the nuclear decommissioning trusts, external pricing vendors are designated for each asset class with each security specifically assigned a primary pricing source. For investments held within commingled funds, fair value is determined at the end of each business day through the net asset value, which is established by obtaining the underlying securities' individual prices from the primary pricing source. A market price secured from the primary source vendor is then evaluated by management in its valuation of the assets within the trusts. As a general approach, fixed income market pricing vendors gather market data (including indices and market research reports) and integrate relative credit information, observed market movements, and sector news into proprietary pricing models, pricing systems, and mathematical tools. Dealer quotes and other market information, including live trading levels and pricing analysts' judgments, are also obtained when available. See Note 1 to the financial statements of Southern Company, Alabama Power, and Georgia Power under "Nuclear Decommissioning" in Item 8 of the Form 10-K for additional information.

"Other investments" include investments that are not traded in the open market. The fair value of these investments have been determined based on market factors including comparable multiples and the expectations regarding cash flows and business plan executions.

141

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

As of March 31, 2016, the fair value measurements of private equity investments held in the nuclear decommissioning trust that are calculated at net asset value per share (or its equivalent) as a practical expedient, as well as the nature and risks of those investments, were as follows:

As of March 31, 2016:	Fair Value		Unfunded Commitments		Redemption Frequency	Redemption Notice Period
	(in millions)
Southern Company	$	16	$	29	Not Applicable	Not Applicable
Alabama Power	$	16	$	29	Not Applicable	Not Applicable

Private equity funds include a fund-of-funds that invests in high-quality private equity funds across several market sectors, a fund that invests in real estate assets, and a fund that acquires companies to create resale value. Private equity funds do not have redemption rights. Distributions from these funds will be received as the underlying investments in the funds are liquidated. Liquidations are expected to occur at various times over the next ten years.

As of March 31, 2016, 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, including securities due within one year:
Southern Company	$	28,341	$	29,827
Alabama Power	$	7,089	$	7,688
Georgia Power	$	10,549	$	11,400
Gulf Power	$	1,303	$	1,366
Mississippi Power	$	3,209	$	2,938
Southern Power	$	3,123	$	3,171

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 available to the registrants.

(D) STOCKHOLDERS' EQUITY

Earnings per Share

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

	Three Months Ended March 31, 2016	Three Months Ended March 31, 2015
	(in millions)
As reported shares	916	910
Effect of options and performance share award units	6	5
Diluted shares	922	915

142

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Stock options and performance share award units that were not included in the diluted earnings per share calculation because they were anti-dilutive were immaterial for the three months ended March 31, 2016 and 2015.

Changes in Stockholders' Equity

The following table presents year-to-date changes in stockholders' equity of Southern Company:

	Number of Common Shares			Common Stockholders' Equity			Preferred and Preference Stock of Subsidiaries					Total Stockholders' Equity
	Issued	Treasury							Noncontrolling Interests(*)
	(in thousands)			(in millions)
Balance at December 31, 2015	915,073	(3,352	)	$	20,592		$	609	$	781		$	21,982
Consolidated net income attributable to Southern Company	—	—		485			—		—			485
Other comprehensive income (loss)	—	—		(114		)	—		—			(114		)
Stock issued	6,572	—		270			—		—			270
Stock-based compensation	—	—		60			—		—			60
Cash dividends on common stock	—	—		(497		)	—		—			(497		)
Contributions from noncontrolling interests	—	—		—			—		129			129
Distributions to noncontrolling interests	—	—		—			—		(4		)	(4		)
Purchase of membership interests from noncontrolling interests	—	—		—			—		(129		)	(129		)
Net income attributable to noncontrolling interests	—	—		—			—		1			1
Other	—	(35	)	1			—		—			1
Balance at March 31, 2016	921,645	(3,387	)	$	20,797		$	609	$	778		$	22,184
Balance at December 31, 2014	908,502	(725	)	$	19,949		$	756	$	221		$	20,926
Consolidated net income attributable to Southern Company	—	—		508			—		—			508
Other comprehensive income (loss)	—	—		(15		)	—		—			(15		)
Stock issued	3,094	—		112			—		—			112
Stock-based compensation	—	—		53			—		—			53
Stock repurchased, at cost	—	(2,599	)	(115		)	—		—			(115		)
Cash dividends on common stock	—	—		(478		)	—		—			(478		)
Other	—	(11	)	3			—		—			3
Balance at March 31, 2015	911,596	(3,335	)	$	20,017		$	756	$	221		$	20,994

(*) Primarily related to Southern Power Company.

143

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' pollution control revenue bonds. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of March 31, 2016 was approximately $1.8 billion (comprised of approximately $810 million at Alabama Power, $868 million at Georgia Power, $82 million at Gulf Power, and $40 million at Mississippi Power). In addition, at March 31, 2016, the traditional operating companies had approximately $269 million (comprised of approximately $167 million at Alabama Power, $69 million at Georgia Power, and $33 million at Gulf Power) of fixed rate pollution control revenue bonds outstanding that were required to be reoffered 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. See "Financing Activities" herein for additional information.

The following table outlines the committed credit arrangements by company as of March 31, 2016:

	Expires											Executable Term Loans				Due Within One Year
Company	2016		2017		2018		2020	Total		Unused		One Year		Two Years		Term Out		No Term Out
								(in millions)				(in millions)				(in millions)
Southern Company (a)	$	—	$	—	$	1,000	$1,250	$	2,250	$	2,250	$	—	$	—	$	—	$	—
Alabama Power	40		—		500		800	1,340		1,340		—		—		—		40
Georgia Power	—		—		—		1,750	1,750		1,732		—		—		—		—
Gulf Power	75		40		165		—	280		280		45		—		45		40
Mississippi Power	205		—		—		—	205		180		30		15		45		160
Southern Power Company (b)	—		—		—		600	600		560		—		—		—		—
Other	70		—		—		—	70		70		20		—		20		50
Total	$	390	$	40	$	1,665	$4,400	$	6,495	$	6,412	$	95	$	15	$	110	$	290

(a) Excludes the $8.1 billion Bridge Agreement entered into in September 2015 that will be funded only to the extent necessary to provide financing for the Merger as discussed herein.

(b) Excluding its subsidiaries. See "Project Credit Facilities" below and Note (I) under "Southern Power" for additional information.

Subject to applicable market conditions, Southern Company and its subsidiaries expect to renew or replace their bank credit arrangements as needed, prior to expiration. In connection therewith, Southern Company and its subsidiaries may extend the maturity dates and/or increase or decrease the lending commitments thereunder.

Southern Company intends to fund the cash consideration for the Merger using a mix of debt and equity. Southern Company finances its capital needs on a portfolio basis and expects to issue a minimum of $8.0 billion in debt prior to closing the Merger and a minimum of $1.2 billion in equity during 2016. This capital is expected to provide funding for the Merger, the proposed acquisition of PowerSecure International, Inc. (PowerSecure), and Southern Power and other Southern Company system capital projects. Total capital raised in 2016 may increase due to cash needed at the closing of the Merger, settlement of hedges, and incremental investment opportunities, including additional Southern Power projects in excess of its current capital plans. In addition, Southern Company entered into the $8.1 billion Bridge Agreement on September 30, 2015 to provide financing for the Merger in the event long-term financing is not available. As of March 31, 2016, Southern Company had no outstanding loans under the Bridge Agreement. See Note (I) under "Southern Company – Proposed Merger with AGL Resources" for additional information regarding the Merger. See Note 6 to the financial statements of Southern Company under "Bank Credit Arrangements" in Item 8 of the Form 10-K for additional information regarding the Bridge Agreement.

144

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Southern Power Project Credit Facilities

In connection with the construction of solar facilities by RE Tranquillity LLC, RE Roserock LLC, and RE Garland Holdings LLC, indirect subsidiaries of Southern Power, each subsidiary entered into separate credit agreements (Project Credit Facilities), which are non-recourse to Southern Power (other than the subsidiary party to the agreement). Each Project Credit Facility provides (a) a senior secured construction loan credit facility, (b) a senior secured bridge loan facility, and (c) a senior secured letter of credit facility that is secured by the membership interests of the respective project company. Proceeds from the Project Credit Facilities are being used to finance project costs related to the respective solar facilities currently under construction. Each Project Credit Facility is secured by the assets of the applicable project subsidiary and membership interests of the applicable project subsidiary. The table below summarizes each Project Credit Facility as of March 31, 2016.

Project	Maturity Date	Construction Loan Facility		Bridge Loan Facility		Total		Total Undrawn		Letter of Credit Facility		Total Undrawn
		(in millions)
Tranquillity	Earlier of COD or December 31, 2016	$	86	$	172	$	258	$	52	$	77	$	26
Roserock	Earlier of COD or November 30, 2016	63		180		243		121		23		16
Garland	Earlier of COD or November 30, 2016	86		308		394		309		49		32
Total		$	235	$	660	$	895	$	482	$	149	$	74

The Project Credit Facilities had total amounts outstanding as of March 31, 2016 of $413 million at a weighted average interest rate of 1.99%. For the three months ended March 31, 2016, these credit agreements had a maximum amount outstanding of $413 million, and an average amount outstanding of $260 million at a weighted average interest rate of 1.99%.

Financing Activities

The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first three months of 2016:

Company(a)	Senior Note Issuances		Senior Note Maturities and Redemptions		Revenue Bond Maturities Redemptions and Repurchases		Other Long-Term Debt Issuances			Other Long-Term Debt Redemptions and Maturities(b)
	(in millions)
Alabama Power	$	400	$	200	$	—	$	45		$	—
Georgia Power	650		250		4		—			1
Mississippi Power	—		—		—		1,100			426
Southern Power	—		—		—		2			3
Other	—		—		—		—			4
Elimination(c)	—		—		—		(200		)	—
Total	$	1,050	$	450	$	4	$	947		$	434

(a) Southern Company and Gulf Power did not issue or redeem any long-term debt during the first three months of 2016.    

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

(c) Intercompany loans from Southern Company to Mississippi Power eliminated in Southern Company's Consolidated Financial Statements.

145

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Alabama Power

In January 2016, Alabama Power issued $400 million aggregate principal amount of Series 2016A 4.30% Senior Notes due January 2, 2046. The proceeds were used to repay at maturity $200 million aggregate principal amount of Alabama Power's Series FF 5.20% Senior Notes due January 15, 2016 and for general corporate purposes, including Alabama Power's continuous construction program.

In March 2016, Alabama Power entered into three bank term loan agreements with maturity dates of March 2021, in an aggregate principal amount of $45 million, one of which bears interest at 2.38% per annum and two of which bear interest based on three-month LIBOR.

Georgia Power

In March 2016, Georgia Power issued $325 million aggregate principal amount of Series 2016A 3.25% Senior Notes due April 1, 2026 and $325 million aggregate principal amount of Series 2016B 2.40% Senior Notes due April 1, 2021. An amount equal to the proceeds from the Series 2016A 3.25% Senior Notes due April 1, 2026 will be allocated to eligible green expenditures, including financing of or investments in solar power generation facilities or electric vehicle charging infrastructure, or payments under PPAs served by solar power or wind generation facilities. The proceeds from the Series 2016B 2.40% Senior Notes due April 1, 2021 were used to repay at maturity $250 million aggregate principal amount of Georgia Power's Series 2013B Floating Rate Senior Notes due March 15, 2016, to repay a portion of Georgia Power's short-term indebtedness, and for general corporate purposes, including Georgia Power's continuous construction program.

Mississippi Power

In January 2016, Mississippi Power issued a floating rate promissory note to Southern Company in an aggregate principal amount of up to $275 million, which matures on December 1, 2017, bearing interest based on one-month LIBOR. As of March 31, 2016, Mississippi Power had borrowed $100 million under this promissory note with a $50 million draw occurring on each of January 29, 2016 and March 14, 2016. In addition, on January 19, 2016, Mississippi Power borrowed $100 million from Southern Company pursuant to a promissory note issued in November 2015.

On March 8, 2016, Mississippi Power entered into an unsecured term loan agreement for an aggregate amount of $1.2 billion to repay existing indebtedness and for other general corporate purposes. Mississippi Power borrowed $900 million under the term loan agreement and has the right to borrow the remaining $300 million on or before October 15, 2016, upon satisfaction of certain customary conditions. Mississippi Power used the initial proceeds to repay $900 million in maturing bank notes on March 8, 2016 and expects the remaining $300 million to be used to repay senior notes maturing in October 2016. The term loan pursuant to this agreement matures on April 1, 2018 and bears interest based on one-month LIBOR.

Also in March 2016, Mississippi Power renewed a $10 million short-term note, which matures on June 30, 2016, bearing interest based on three-month LIBOR.

Southern Power

During the three months ended March 31, 2016, Southern Power's subsidiary repaid $3 million of long-term debt payable to Turner Renewable Energy, LLC (TRE) and borrowed $2 million due February 28, 2036 under promissory notes payable to TRE.

During the three months ended March 31, 2016, Southern Power's subsidiaries borrowed $276 million pursuant to the Project Credit Facilities at a weighted average interest rate of 1.99%. In addition, Southern Power's subsidiaries issued $8 million in letters of credit.

(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,

146

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

as amended. No mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2016. Southern Company also provides certain defined benefit pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, Southern Company provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The traditional operating companies fund related other postretirement trusts to the extent required by their respective regulatory commissions.

See Note 2 to the financial statements of Southern Company, Alabama Power, Georgia Power, Gulf Power, and Mississippi Power in Item 8 of the Form 10-K for additional information.

Components of the net periodic benefit costs for the three months ended March 31, 2016 were as follows:

Pension Plans	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power
	(in millions)
Three Months Ended March 31, 2016
Service cost	$	62		$	14		$	17		$	3		$	3
Interest cost	100			24			34			5			5
Expected return on plan assets	(187		)	(46		)	(64		)	(9		)	(9		)
Amortization:
Prior service costs	4			1			1			—			—
Net (gain)/loss	38			10			14			2			2
Net cost	$	17		$	3		$	2		$	1		$	1
Three Months Ended March 31, 2015
Service cost	$	64		$	15		$	18		$	3		$	3
Interest cost	111			26			38			5			5
Expected return on plan assets	(181		)	(45		)	(63		)	(8		)	(8		)
Amortization:
Prior service costs	6			2			3			—			—
Net (gain)/loss	54			14			19			3			3
Net cost	$	54		$	12		$	15		$	3		$	3

147

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 March 31, 2016
Service cost	$	5		$	1		$	2		$	—	$	—
Interest cost	18			5			8			1		1
Expected return on plan assets	(14		)	(6		)	(6		)	—		—
Amortization:
Prior service costs	2			1			—			—		—
Net (gain)/loss	3			—			2			—		—
Net cost	$	14		$	1		$	6		$	1	$	1
Three Months Ended March 31, 2015
Service cost	$	6		$	1		$	2		$	—	$	—
Interest cost	19			5			8			1		1
Expected return on plan assets	(15		)	(6		)	(6		)	—		—
Amortization:
Prior service costs	1			1			—			—		—
Net (gain)/loss	5			—			3			—		—
Net cost	$	16		$	1		$	7		$	1	$	1

148

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

(G) INCOME TAXES

Current and Deferred Income Taxes

Southern Power ITC Carryforwards

As of March 31, 2016, Southern Power had federal ITC carryforwards which are expected to result in $694 million of federal income tax benefits compared to $551 million as of December 31, 2015. The carryforwards as of March 31, 2016 begin expiring in 2034 but are expected to be utilized by the end of 2021.

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 employee stock plans' dividend deduction, non-taxable AFUDC equity, and federal income tax benefits from ITCs and PTCs.

Southern Company's effective tax rate was 30.8% for the three months ended March 31, 2016 compared to 34.3% for the corresponding period in 2015. The effective tax rate decrease was primarily due to increased federal income tax benefits from ITCs and PTCs and lower pre-tax earnings in 2016.

Mississippi Power

Mississippi Power's effective tax rate was (838.7)% for the three months ended March 31, 2016 compared to 10.0% for the corresponding period in 2015. The effective tax rate decrease was primarily due to an increase in tax benefits related to the estimated probable losses on construction of the Kemper IGCC.

Southern Power

Southern Power's effective tax rate was (84.0)% for the three months ended March 31, 2016 compared to 25.8% for the corresponding period in 2015. The effective tax rate decrease was primarily due to increased federal income tax benefits from ITCs related to solar projects expected to be placed in service in 2016 and additional PTCs related to wind projects in 2016 compared to 2015.

Unrecognized Tax Benefits

See Note 5 to the financial statements of each registrant under "Unrecognized Tax Benefits" in Item 8 of the Form 10-K for additional information.

Changes during 2016 for unrecognized tax benefits were as follows:

	Mississippi Power		Southern Power		Southern Company
	(in millions)
Unrecognized tax benefits as of December 31, 2015	$	421	$	8	$	433
Tax positions from current periods	—		5		5
Balance as of March 31, 2016	$	421	$	13	$	438

The tax positions from current periods primarily relate to federal income tax benefits from ITCs.

149

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

The impact on the effective tax rate, if recognized, is as follows:

	As of March 31, 2016							As of December 31, 2015
	Mississippi Power			Southern Power		Southern Company		Southern Company
	(in millions)
Tax positions impacting the effective tax rate	$	(2	)	$	13	$	15	$	10
Tax positions not impacting the effective tax rate	423			—		423		423
Balance of unrecognized tax benefits	$	421		$	13	$	438	$	433

The tax positions impacting the effective tax rate primarily relate to federal income tax benefits from ITCs. The tax positions not impacting the effective tax rate relate to deductions for Kemper IGCC-related research and experimental (R&E) expenditures. See "Section 174 Research and Experimental Deduction" below for additional information. These amounts are presented on a gross basis without considering the related federal or state income tax impact.

Accrued interest for unrecognized tax benefits was immaterial for all periods presented.

All of the registrants classify interest on tax uncertainties as interest expense. None of the registrants accrued any penalties on uncertain tax positions.

It is reasonably possible that the amount of the unrecognized tax benefits could change within 12 months. The settlement of federal and state audits could impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined.

The IRS has finalized its audits of Southern Company's consolidated federal income tax returns through 2012. Southern Company has filed its 2013 and 2014 federal income tax returns and has received partial acceptance letters from the IRS; however, the IRS has not finalized its audits. Southern Company is a participant in the Compliance Assurance Process of the IRS. The audits for the Southern Company's state income tax returns have either been concluded, or the statute of limitations has expired, for years prior to 2011.

Section 174 Research and Experimental Deduction

Southern Company has reflected deductions for R&E expenditures related to the Kemper IGCC in its federal income tax calculations since 2013 and has filed amended federal income tax returns for 2008 through 2013 to also include such deductions.

The Kemper IGCC is based on first-of-a-kind technology, and Southern Company and Mississippi Power believe that a significant portion of the plant costs qualify as deductible R&E expenditures 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, Southern Company and Mississippi Power had related unrecognized tax benefits associated with these R&E deductions of approximately $423 million and associated interest of $12 million as of March 31, 2016. The ultimate outcome of this matter cannot be determined at this time.

(H) DERIVATIVES

Southern Company, the traditional operating companies, and Southern Power are exposed to market risks, primarily commodity price risk and interest rate risk. To manage the volatility attributable to these exposures, each company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to each company's policies in areas such as counterparty exposure and risk management practices. Each company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using

150

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

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) for additional information. In the statements of cash flows, the cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities.

Energy-Related Derivatives

The traditional operating companies and Southern Power enter into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the traditional operating companies have limited exposure to market volatility in commodity fuel prices and prices of electricity. Each of the traditional operating companies manages fuel-hedging programs, implemented per the guidelines of their respective state PSCs, through the use of financial derivative contracts, which is expected to continue to mitigate price volatility. The traditional operating companies (with respect to wholesale generating capacity) and Southern Power have limited exposure to market volatility in commodity fuel prices and prices of electricity because their long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, the traditional operating companies and Southern Power may be exposed to market volatility in energy-related commodity prices to the extent any uncontracted wholesale generating capacity is used to sell electricity.

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) are initially deferred in OCI before being recognized in the statements of income in the same period as the hedged transactions are reflected in earnings.

• Not Designated — Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.

Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric industry. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered.

At March 31, 2016, 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	235	2020	2017
Alabama Power	60	2019	—
Georgia Power	65	2019	—
Gulf Power	74	2020	—
Mississippi Power	28	2018	—
Southern Power	8	2016	2017

151

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

In addition to the volumes discussed in the above table, the traditional operating companies and Southern Power enter into physical natural gas supply contracts that provide the option to sell back excess gas due to operational constraints. The maximum expected volume of natural gas subject to such a feature is 4 million mmBtu for Southern Company and Georgia Power.

For cash flow hedges, the amounts expected to be reclassified from accumulated OCI to earnings for the next 12-month period ending March 31, 2017 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. Fair value gains or losses on derivatives that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.

152

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

At March 31, 2016, the following interest rate derivatives were outstanding:

	Notional Amount			Interest Rate Received	Weighted Average Interest Rate Paid	Hedge Maturity Date		Fair Value Gain (Loss) at March 31, 2016
	(in millions)							(in millions)
Cash Flow Hedges of Forecasted Debt
Southern Company	$	1,500		3-month LIBOR	2.14%	November 2026		$	(55	)
Southern Company	1,200			3-month LIBOR	2.60%	November 2046		(127		)
Gulf Power	80			3-month LIBOR	2.32%	December 2026		(4		)
Cash Flow Hedges of Existing Debt
Georgia Power	200			3-month LIBOR + 0.40%	1.01%	August 2016		—
Fair Value Hedges on Existing Debt
Southern Company	250			1.30%	3-month LIBOR + 0.17%	August 2017		1
Southern Company	300			2.75%	3-month LIBOR + 0.92%	June 2020		10
Georgia Power	250			5.40%	3-month LIBOR + 4.02%	June 2018		3
Georgia Power	200			4.25%	3-month LIBOR + 2.46%	December 2019		6
Georgia Power	500			1.95%	3-month LIBOR + 0.76%	December 2018		5
Derivatives not Designated as Hedges
Southern Power	65		(a,d)	3-month LIBOR	2.50%	October 2016	(e)	—
Southern Power	47		(b,d)	3-month LIBOR	2.21%	October 2016	(e)	—
Southern Power	65		(c,d)	3-month LIBOR	2.21%	November 2016	(f)	—
Total	$	4,657						$	(161	)

(a) Swaption at RE Tranquillity LLC. See Note 12 to the financial statements of Southern Company and Note 2 to the financial statements of Southern Power in Item 8 of the Form 10-K for additional information.

(b) Swaption at RE Roserock LLC. See Note 12 to the financial statements of Southern Company and Note 2 to the financial statements of Southern Power in Item 8 of the Form 10-K for additional information.

(c) Swaption at RE Garland Holdings LLC. See Note 12 to the financial statements of Southern Company and Note 2 to the financial statements of Southern Power in Item 8 of the Form 10-K for additional information.

(d) Amortizing notional amount.

(e) Represents the mandatory settlement date. Settlement will be based on a 15-year amortizing swap.

(f) Represents the mandatory settlement date. Settlement will be based on a 12-year amortizing swap.

153

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

The estimated pre-tax gains (losses) that will be reclassified from accumulated OCI to interest expense for the next 12-month period ending March 31, 2017 are immaterial for all registrants. Southern Company and certain subsidiaries have deferred gains and losses that are expected to be amortized into earnings through 2046.

Derivative Financial Statement Presentation and Amounts

At March 31, 2016, the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows:

Asset Derivatives at March 31, 2016
	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	$	2	$	1	$	1	$	—	$	—
Other deferred charges and assets	5		2		3		—		—
Total derivatives designated as hedging instruments for regulatory purposes	$	7	$	3	$	4	$	—	$	—	N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Other current assets(*)	$	4	$	—	$	—	$	—	$	—	$	4
Interest rate derivatives:
Other current assets	18		—		7		—		—		—
Other deferred charges and assets	14		—		7		—		—		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	36	$	—	$	14	$	—	$	—	$	4
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets(*)	$	1	$	—	$	—	$	—	$	—	$	1
Interest rate derivatives:
Other current assets(*)	1		—		—		—		—		1
Total derivatives not designated as hedging instruments	$	2	$	—	$	—	$	—	$	—	$	2
Total asset derivatives	$	45	$	3	$	18	$	—	$	—	$	6

(*) Southern Power includes current assets related to derivatives in "Assets from risk management activities."

154

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Liability Derivatives at March 31, 2016
	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(*)	$	124	$	37	$	9	$	49	$	29
Other deferred credits and liabilities	74		12		2		45		15
Total derivatives designated as hedging instruments for regulatory purposes	$	198	$	49	$	11	$	94	$	44	N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Liabilities from risk management activities(*)	$	2	$	—	$	—	$	—	$	—	$	2
Interest rate derivatives:
Liabilities from risk management activities(*)	193		—		—		5		—		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	195	$	—	$	—	$	5	$	—	$	2
Derivatives not designated as hedging instruments
Energy-related derivatives:
Liabilities from risk management activities(*)	$	1	$	—	$	—	$	—	$	—	$	1
Total liability derivatives	$	394	$	49	$	11	$	99	$	44	$	3

(*) Georgia Power, Mississippi Power, and Southern Power include current liabilities related to derivatives in "Other current liabilities."

155

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

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

Asset Derivatives at December 31, 2015
	Fair Value
Derivative Category and Balance Sheet Location	Southern Company		Alabama Power		Georgia Power		Gulf Power		Mississippi Power		Southern Power
	(in millions)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets	$	3	$	1	$	2	$	—	$	—	N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Other current assets(*)	$	3	$	—	$	—	$	—	$	—	$	3
Interest rate derivatives:
Other current assets	19		—		5		1		—		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	22	$	—	$	5	$	1	$	—	$	3
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets(*)	$	1	$	—	$	—	$	—	$	—	$	1
Interest rate derivatives:
Other current assets(*)	3		—		—		—		—		3
Total derivatives not designated as hedging instruments	$	4	$	—	$	—	$	—	$	—	$	4
Total asset derivatives	$	29	$	1	$	7	$	1	$	—	$	7

(*) Southern Power includes current assets related to derivatives in "Assets from risk management activities."

156

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Liability Derivatives at December 31, 2015
	Fair Value
Derivative Category and Balance Sheet Location	Southern Company		Alabama Power		Georgia Power		Gulf Power		Mississippi Power		Southern Power
	(in millions)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Liabilities from risk management activities(*)	$	130	$	40	$	12	$	49	$	29
Other deferred credits and liabilities	87		15		3		51		18
Total derivatives designated as hedging instruments for regulatory purposes	$	217	$	55	$	15	$	100	$	47	N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Liabilities from risk management activities(*)	$	2	$	—	$	—	$	—	$	—	$	2
Interest rate derivatives:
Liabilities from risk management activities	23		15		—		—		—		—
Other deferred credits and liabilities	7		—		6		—		—		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	32	$	15	$	6	$	—	$	—	$	2
Derivatives not designated as hedging instruments
Energy-related derivatives:
Liabilities from risk management activities(*)	$	1	$	—	$	—	$	—	$	—	$	1
Total liability derivatives	$	250	$	70	$	21	$	100	$	47	$	3

(*) Georgia Power, Mississippi Power, and Southern Power include current liabilities related to derivatives 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 and interest rate derivative contracts at March 31, 2016 and December 31, 2015 are presented in the following tables.

157

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Derivative Contracts at March 31, 2016
	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		$	3		$	4		$	—	$	—	$	5
Gross amounts not offset in the Balance Sheet (b)	(10		)	(3		)	(3		)	—		—		(2		)
Net energy-related derivative assets	$	2		$	—		$	1		$	—	$	—	$	3
Interest rate derivatives:
Interest rate derivatives presented in the Balance Sheet (a)	$	33		$	—		$	14		$	—	$	—	$	1
Gross amounts not offset in the Balance Sheet (b)	(21		)	—			—			—		—		—
Net interest rate derivative assets	$	12		$	—		$	14		$	—	$	—	$	1
Liabilities
Energy-related derivatives:
Energy-related derivatives presented in the Balance Sheet (a)	$	201		$	49		$	11		$	94	$	44	$	3
Gross amounts not offset in the Balance Sheet (b)	(10		)	(3		)	(3		)	—		—		(2		)
Net energy-related derivative liabilities	$	191		$	46		$	8		$	94	$	44	$	1
Interest rate derivatives:
Interest rate derivatives presented in the Balance Sheet (a)	$	193		$	—		$	—		$	5	$	—	$	—
Gross amounts not offset in the Balance Sheet (b)	(21		)	—			—			—		—		—
Net interest rate derivative liabilities	$	172		$	—		$	—		$	5	$	—	$	—

(a) None of the registrants offsets fair value amounts for multiple derivative instruments executed with the same counterparty on the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented on the balance sheets are the same.

(b) Includes gross amounts subject to netting terms that are not offset on the balance sheets and any cash/financial collateral pledged or received.

158

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Derivative Contracts at December 31, 2015
	Fair Value
	Southern Company			Alabama Power			Georgia Power			Gulf Power		Mississippi Power		Southern Power
	(in millions)
Assets
Energy-related derivatives:
Energy-related derivatives presented in the Balance Sheet (a)	$	7		$	1		$	2		$	—	$	—	$	4
Gross amounts not offset in the Balance Sheet (b)	(6		)	(1		)	(2		)	—		—		(1		)
Net energy-related derivative assets	$	1		$	—		$	—		$	—	$	—	$	3
Interest rate derivatives:
Interest rate derivatives presented in the Balance Sheet (a)	$	22		$	—		$	5		$	1	$	—	$	4
Gross amounts not offset in the Balance Sheet (b)	(9		)	—			(4		)	—		—		—
Net interest rate derivative assets	$	13		$	—		$	1		$	1	$	—	$	4
Liabilities
Energy-related derivatives:
Energy-related derivatives presented in the Balance Sheet (a)	$	220		$	55		$	15		$	100	$	47	$	3
Gross amounts not offset in the Balance Sheet (b)	(6		)	(1		)	(2		)	—		—		(1		)
Net energy-related derivative liabilities	$	214		$	54		$	13		$	100	$	47	$	2
Interest rate derivatives:
Interest rate derivatives presented in the Balance Sheet (a)	$	30		$	15		$	6		$	—	$	—	$	—
Gross amounts not offset in the Balance Sheet (b)	(9		)	—			(4		)	—		—		—
Net interest rate derivative liabilities	$	21		$	15		$	2		$	—	$	—	$	—

(a) None of the registrants offsets fair value amounts for multiple derivative instruments executed with the same counterparty on the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented on the balance sheets are the same.

(b) Includes gross amounts subject to netting terms that are not offset on the balance sheets and any cash/financial collateral pledged or received.

159

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

At March 31, 2016 and December 31, 2015, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred were as follows:

Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet at March 31, 2016
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	$	(124	)	$	(37	)	$	(9	)	$	(49	)	$	(29	)
Other regulatory assets, deferred	(74		)	(12		)	(2		)	(45		)	(15		)
Other regulatory liabilities, current (a)	2			1			1			—			—
Other regulatory liabilities, deferred (b)	5			2			3			—			—
Total energy-related derivative gains (losses)	$	(191	)	$	(46	)	$	(7	)	$	(94	)	$	(44	)

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

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

Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet at December 31, 2015
Derivative Category and Balance Sheet Location	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power
	(in millions)
Energy-related derivatives:
Other regulatory assets, current	$	(130	)	$	(40	)	$	(12	)	$	(49	)	$	(29	)
Other regulatory assets, deferred	(87		)	(15		)	(3		)	(51		)	(18		)
Other regulatory liabilities, current(*)	3			1			2			—			—
Total energy-related derivative gains (losses)	$	(214	)	$	(54	)	$	(13	)	$	(100	)	$	(47	)

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

For the three months ended March 31, 2016 and 2015, the pre-tax effects of interest rate derivatives designated as cash flow hedging instruments were as follows:

Derivatives in Cash Flow Hedging Relationships	Gain (Loss) Recognized in OCI on Derivative (Effective Portion)						Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)
							Statements of Income Location	Amount
	2016			2015				2016			2015
	(in millions)							(in millions)
Southern Company
Interest rate derivatives	$	(190	)	$	(29	)	Interest expense, net of amounts capitalized	$	(3	)	$	(2	)
Alabama Power
Interest rate derivatives	$	(4	)	$	(6	)	Interest expense, net of amounts capitalized	$	(1	)	$	(1	)
Georgia Power
Interest rate derivatives	$	—		$	(23	)	Interest expense, net of amounts capitalized	$	(1	)	$	(1	)
Gulf Power
Interest rate derivatives	$	(5	)	$	—		Interest expense, net of amounts capitalized	$	—		$	—

For the three months ended March 31, 2016 and 2015, the pre-tax effects of energy-related derivatives designated as cash flow hedging instruments recognized in OCI and those reclassified from accumulated OCI into earnings were immaterial for all registrants.

160

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

For the three months ended March 31, 2016 and 2015, the pre-tax effects of interest rate derivatives designated as fair value hedging instruments were as follows:

Derivatives in Fair Value Hedging Relationships
		Gain (Loss)
Derivative Category	Statements of Income Location	2016		2015
		(in millions)
Southern Company
Interest rate derivatives:	Interest expense, net of amounts capitalized	$	20	$	7
Georgia Power
Interest rate derivatives:	Interest expense, net of amounts capitalized	$	14	$	6

For the three months ended March 31, 2016 and 2015, the pre-tax effects of interest rate derivatives designated as fair value hedging instruments were offset by changes to the carrying value of long-term debt. There was no material ineffectiveness recorded in earnings for any registrant for any period presented.

For the three months ended March 31, 2016 and 2015, the pre-tax effects of energy-related derivatives and interest rate derivatives not designated as hedging instruments were immaterial for all registrants.

Contingent Features

The registrants do not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain Southern Company subsidiaries. At March 31, 2016, the registrants' collateral posted with their derivative counterparties was immaterial.

At March 31, 2016, the fair value of derivative liabilities with contingent features was $49 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 $49 million and include certain agreements that could require collateral in the event that one or more Southern Company power pool participants has a credit rating change to below investment grade.

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

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

(I) ACQUISITIONS

Southern Company

Proposed Merger with AGL Resources

On August 23, 2015, Southern Company entered into the Merger Agreement to acquire AGL Resources. Under the terms of the Merger Agreement, subject to the satisfaction or waiver (if permissible under applicable law) of

161

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

specified conditions, Merger Sub will be merged with and into AGL Resources. AGL Resources will survive the Merger and become a wholly-owned, direct subsidiary of Southern Company.

The Merger will be accounted for using the acquisition method of accounting whereby the assets acquired and liabilities assumed are recognized at fair value as of the acquisition date. The excess of the purchase price over the fair values of AGL Resources' assets and liabilities will be recorded as goodwill. Southern Company expects total cash of $8.2 billion to be required to fund the purchase price of approximately $8.0 billion to acquire AGL Resources common stock, options to purchase shares of AGL Resources common stock, and restricted stock units payable in shares of AGL Resources common stock and to fund acquisition-related expenses and financing costs of approximately $200 million. Southern Company will also assume AGL Resources' outstanding indebtedness.

Through May 5, 2016, the Maryland PSC, the Georgia PSC, the California Public Utilities Commission, and the Virginia State Corporation Commission have approved the Merger. On April 15, 2016, Southern Company, AGL Resources, and Northern Illinois Gas Company (collectively, the Joint Applicants) and the Retail Energy Supply Association filed a settlement agreement with the Illinois Commerce Commission. On April 28, 2016, the Joint Applicants, the Illinois Attorney General's Office, and the Citizens Utility Board filed a settlement agreement with the Illinois Commerce Commission. Collectively, these agreements resolve all remaining contested issues for Illinois Commerce Commission approval of the Merger. On May 5, 2016, Southern Company, AGL Resources, Merger Sub, Pivotal Utility Holdings, Inc. d/b/a Elizabethtown Gas, the Division of Rate Counsel, the Staff of the New Jersey Board of Public Utilities, and New Jersey Large Energy Users Coalition entered into a comprehensive settlement agreement relating to the New Jersey Board of Public Utilities review of the Merger. Additionally, the Federal Communications Commission (FCC) has approved the transfer of control over the FCC licenses of certain AGL Resources subsidiaries. Consummation of the Merger remains subject to the satisfaction or waiver of certain closing conditions, including, among others, (i) the approval of the Illinois Commerce Commission and the New Jersey Board of Public Utilities and other approvals required under applicable state laws, (ii) the absence of a judgment, order, decision, injunction, ruling, or other finding or agency requirement of a governmental entity prohibiting the consummation of the Merger, and (iii) other customary closing conditions, including (a) subject to certain materiality qualifiers, the accuracy of each party's representations and warranties and (b) each party's performance in all material respects of its obligations under the Merger Agreement.

During the first quarter 2016, Southern Company recorded in its statements of income external transaction costs for financing, legal, and consulting services associated with the proposed Merger of approximately $20 million, of which $6 million is included in operating expenses and $14 million is included in other income and (expense).

The ultimate outcome of these matters cannot be determined at this time. See Note 12 to the financial statements of Southern Company under "Southern Company – Proposed Merger with AGL Resources" in Item 8 of the Form 10-K for additional information.

Merger Financing

Southern Company intends to fund the cash consideration for the Merger using a mix of debt and equity. Southern Company expects to issue the debt to fund the cash consideration for the Merger in several tranches including long-dated maturities. The amount of debt issued at each maturity will depend on prevailing market conditions at the time of the offering and other factors. In addition, Southern Company entered into the $8.1 billion Bridge Agreement on September 30, 2015 to provide financing for the Merger in the event long-term financing is not available. See Note 6 to the financial statements of Southern Company under "Bank Credit Arrangements" in Item 8 of the Form 10-K for additional information regarding the Bridge Agreement.

Proposed Acquisition of PowerSecure

On February 24, 2016, Southern Company entered into an Agreement and Plan of Merger to acquire PowerSecure. Under the terms of this merger agreement, the stockholders of PowerSecure will be entitled to receive $18.75 in cash for each share of common stock in a transaction with a total purchase price of approximately $431 million.

162

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Following this transaction, PowerSecure will become a wholly-owned subsidiary of Southern Company. This transaction is expected to close in May 2016. The ultimate outcome of this matter cannot be determined at this time.

Southern Power

See Note 2 to the financial statements of Southern Power and Note 12 to the financial statements of Southern Company under "Southern Power" in Item 8 of the Form 10-K for additional information. During the first quarter 2016, the fair values of the assets and liabilities acquired of Lost Hills, Blackwell, North Star, and Morelos were finalized and there were no changes.

During 2016, in accordance with its overall growth strategy, Southern Power acquired or contracted to acquire through its wholly-owned subsidiaries, Southern Renewable Partnerships, LLC or Southern Renewable Energy, Inc., the projects set forth in the following table. Acquisition-related costs were expensed as incurred and were not material. The acquisitions do not include any contingent consideration unless specifically noted.

Project Facility	Seller; Acquisition Date	Approx. Nameplate Capacity	Location	Southern Power Percentage Ownership		Expected/Actual COD	PPA Counterparties for Plant Output	PPA Contract Period	Approx. Purchase Price
		(MW)							(in millions)
SOLAR
Calipatria	Solar Frontier Americas Holding, LLC February 11, 2016	20	Imperial County, CA	90	%	February 11, 2016	San Diego Gas & Electric Company	20 years	$	51	(a)
East Pecos	First Solar, Inc. March 4, 2016	120	Pecos County, TX	100	%	Fourth quarter 2016	Austin Energy	15 years	$	41	(b)
WIND
Grant Wind	Apex Clean Energy Holdings, LLC April 7, 2016	151	Grant County, OK	100	%	April 8, 2016	Western Farmers, East Texas, and Northeast Texas Electric Cooperative	20 years	$	258	(c)
Passadumkeag	Quantam Wind Acquisition I, LLC	40	Penobscot County, ME	100	%	Second quarter 2016	Western Massachusetts Electric Company	15 years	$	127	(d)

(a) Calipatria - The total purchase price, including the minority owner, TRE's 10% ownership interest and contingent consideration of $6 million, is approximately $57 million. As of March 31, 2016, the fair values of the assets and liabilities acquired through the business combination were recorded as follows: $58 million as property, plant, and equipment, $1 million as a transmission interconnection prepaid, and $2 million as payables; however, the allocation of the purchase price to individual assets has not been finalized.

(b) East Pecos - The total purchase price is approximately $41 million. As of March 31, 2016, the fair values of the assets acquired through the business combination were recorded as $41 million to CWIP; however, the allocation of the purchase price to individual assets has not been finalized. Total construction costs, which include the acquisition price allocated to CWIP, are expected to be approximately $200 million to $220 million. The ultimate outcome of this matter cannot be determined at this time.

(c) Grant Wind - Subsequent to March 31, 2016, Southern Power acquired all of the outstanding membership interests of Grant Wind, LLC. The purchase price includes approximately $23 million of contingent consideration which may be adjusted based on performance testing and production over the first 10 years of operation.

(d) Passadumkeag - On March 11, 2016, Southern Power entered into an agreement to acquire all of the outstanding membership interests of Quantum Wind Acquisition I, LLC, which is expected to close in the second quarter 2016. The ultimate outcome of this matter cannot be determined at this time.

Construction Projects

During the first quarter 2016, in accordance with its overall growth strategy, Southern Power completed construction of and placed in service the Butler Solar Farm and Pawpaw solar facilities. In addition, Southern Power

163

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

continued construction of the projects set forth in the table below. Through March 31, 2016, total costs of construction incurred for the projects below were $2.2 billion, of which $1.5 billion remains in CWIP. The ultimate outcome of these matters cannot be determined at this time.

Solar Facility	Seller	Approx. Nameplate Capacity	Location	Expected/Actual COD	PPA Counterparties for Plant Output	PPA Contract Period	Estimated Construction Costs
		(MW)					(in millions)
Butler	CERSM, LLC and Community Energy, Inc.	103	Taylor County, GA	Fourth quarter 2016	Georgia Power(a)	30 years	$	220	-	230	(b)
Desert Stateline	First Solar, Inc.	299(c)	San Bernardino County, CA	Through third quarter 2016	Southern California Edison Company (SCE)	20 years	$	1,200	-	1,300	(d)
Garland and Garland A	Recurrent Energy, LLC	205	Kern County, CA	Fourth quarter 2016   Third quarter 2016	SCE	15 years and 20 years	$	532	-	552	(e,f)
Roserock	Recurrent Energy, LLC	160	Pecos County, TX	Fourth quarter 2016	Austin Energy	20 years	$	333	-	353	(e,f)
Sandhills	N/A	146	Taylor County, GA	Fourth quarter 2016	Cobb, Flint, Irwin, Middle Georgia and Sawnee Electric Membership Corporations	25 years	$	260	-	280
Tranquillity	Recurrent Energy, LLC	205	Fresno County, CA	Third quarter 2016	Shell Energy North America (US), LP/SCE	18 years	$	473	-	493	(f,g)

(a) Butler - Affiliate PPA subject to FERC approval.

(b) Butler - Total estimated construction costs include the acquisition price of all outstanding membership interests of the related entity.

(c) Desert Stateline - The facility has a total of 299 MWs, of which 110 MWs were placed in service in the fourth quarter 2015 and 76 MWs were placed in service in the first quarter 2016. Subsequent to March 31, 2016, 38 MWs were placed in service. The remaining 75 MWs are expected to be placed in service by the end of the third quarter 2016.

(d) Desert Stateline - On March 29, 2016, Southern Power acquired an additional 15% interest in Desert Stateline. As a result, Southern Power and the class B member are entitled to 66% and 34%, respectively, of all cash distributions from Desert Stateline. In addition, Southern Power will continue to be entitled to substantially all of the federal tax benefits with respect to the transaction. Total estimated construction costs include the acquisition price allocated to CWIP; however, the allocation of the purchase price to individual assets has not been finalized.

(e) Total estimated construction costs include the acquisition price allocated to CWIP. During the first quarter 2016, the allocation of the purchase price to individual assets was finalized with no changes.

(f) Southern Power owns 100% of the class A membership interests and a wholly-owned subsidiary of the seller owns 100% of the class B membership interests. Southern Power and the class B member are entitled to 51% and 49%, respectively, of all cash distributions from the project.

(g) Total estimated construction costs include the acquisition price allocated to CWIP; however, the allocation of the purchase price to individual assets has not been finalized.

164

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 $97 million and $114 million for the three months ended March 31, 2016 and March 31, 2015, respectively. The "All Other" column includes parent Southern Company, which does not allocate operating expenses to business segments. Also, this category includes segments below the quantitative threshold for separate disclosure. These segments include investments in telecommunications and leveraged lease projects. All other inter-segment revenues are not material.

Financial data for business segments and products and services for the three months ended March 31, 2016 and 2015 was as follows:

	Electric Utilities
	Traditional Operating Companies		Southern Power		Eliminations			Total		All Other			Eliminations			Consolidated
	(in millions)
Three Months Ended March 31, 2016:
Operating revenues	$	3,742	$	315	$	(103	)	$	3,954	$	47		$	(36	)	$	3,965
Segment net income (loss)(a)(b)	464		50		—			514		(26		)	(3		)	485
Total assets at March 31, 2016	$	69,240	$	8,999	$	(396	)	$	77,843	$	2,070		$	(1,178	)	$	78,735
Three Months Ended March 31, 2015:
Operating revenues	$	3,948	$	348	$	(124	)	$	4,172	$	40		$	(29	)	$	4,183
Segment net income (loss)(a)(b)	477		33		—			510		3			(5		)	508
Total assets at December 31, 2015	$	69,052	$	8,905	$	(397	)	$	77,560	$	1,819		$	(1,061	)	$	78,318

(a) Attributable to Southern Company.

(b) Segment net income (loss) for the traditional operating companies includes pre-tax charges for estimated probable losses on the Kemper IGCC of $53 million ($33 million after tax) and $9 million ($6 million after tax) for the three months ended March 31, 2016 and 2015, respectively. See Note (B) under "Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" for additional information.

Products and Services

	Electric Utilities' Revenues
Period	Retail		Wholesale		Other		Total
	(in millions)
Three Months Ended March 31, 2016	$	3,377	$	396	$	181	$	3,954
Three Months Ended March 31, 2015	3,542		467		163		4,172

165

PART II — OTHER INFORMATION

Item 1. Legal Proceedings.

See the Notes to the Condensed Financial Statements herein for information regarding certain legal and administrative proceedings in which the registrants are involved.

Item 1A. Risk Factors.

See RISK FACTORS in Item 1A of the Form 10-K for a discussion of the risk factors of the registrants. There have been no material changes to these risk factors from those previously disclosed in the Form 10-K.

Item 6.    Exhibits.

The exhibits below with an asterisk (*) preceding the exhibit number are filed herewith. The remaining exhibits have previously been filed with the SEC and are incorporated herein by reference. The exhibits marked with a pound sign (#) are management contracts or compensatory plans or arrangements.

		(4) Instruments Describing Rights of Security Holders, Including Indentures
		Georgia Power
		(c)1	-	Fifty-fourth Supplemental Indenture to Senior Note Indenture, dated as of March 8, 2016, providing for the issuance of the Series 2016A 3.250% Senior Notes due April 1, 2026. (Designated in Form 8-K dated March 2, 2016, File No. 1-6468, as Exhibit 4.2(a).)
		(c)2	-	Fifty-fifth Supplemental Indenture to Senior Note Indenture, dated as of March 8, 2016, providing for the issuance of the Series 2016B 2.400% Senior Notes due April 1, 2021. (Designated in Form 8-K dated March 2, 2016, File No. 1-6468, as Exhibit 4.2(b).)
	*	(c)3	-	Amendment No. 2 to Loan Guarantee Agreement between Georgia Power and the DOE, dated as of March 9, 2016.
		Mississippi Power
	*	(e)1	-	Term Loan Agreement among Mississippi Power and the lenders identified therein, dated as of March 8, 2016.
		(10) Material Contracts
		Mississippi Power
#	*	(e)1	-	Letter Agreement between Mississippi Power and Emile J. Troxclair III dated December 11, 2014.
#	*	(e)2	-	Performance Award Agreement between Southern Company Services, Inc. and Emile J. Troxclair III effective as of January 3, 2015.
		(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, 2015, File No. 1-3526 as Exhibit 24(a).)
		Alabama Power
		(b)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2015, File No. 1-3164 as Exhibit 24(b).)
		Georgia Power
		(c)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2015, File No. 1-6468 as Exhibit 24(c).)

166

	Gulf Power
	(d)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2015, File No. 001-31737 as Exhibit 24(d).)
	Mississippi Power
	(e)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2015, File No. 001-11229 as Exhibit 24(e)1.)
	(e)2	-	Power of Attorney for Anthony L. Wilson. (Designated in the Form 10-K for the year ended December 31, 2015, File No. 001-11229 as Exhibit 24(e)2.)
	Southern Power
	(f)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2015, File No. 333-98553 as Exhibit 24(f)1.)
	(f)2	-	Power of Attorney for Joseph A. Miller. (Designated in the Form 10-K for the year ended December 31, 2015, File No. 333-98553 as Exhibit 24(f)2.)
	(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.

167

	Southern Power
*	(f)1	-	Certificate of Southern Power Company's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
*	(f)2	-	Certificate of Southern Power Company's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
	(32) Section 906 Certifications
	Southern Company
*	(a)	-	Certificate of Southern Company's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
	Alabama Power
*	(b)	-	Certificate of Alabama Power's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
	Georgia Power
*	(c)	-	Certificate of Georgia Power's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
	Gulf Power
*	(d)	-	Certificate of Gulf Power's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
	Mississippi Power
*	(e)	-	Certificate of Mississippi Power's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
	Southern Power
*	(f)	-	Certificate of Southern Power Company's Chief Executive Officer and Chief Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.
	(101) XBRL – Related Documents
*	INS	-	XBRL Instance Document
*	SCH	-	XBRL Taxonomy Extension Schema Document
*	CAL	-	XBRL Taxonomy Calculation Linkbase Document
*	DEF	-	XBRL Definition Linkbase Document
*	LAB	-	XBRL Taxonomy Label Linkbase Document
*	PRE	-	XBRL Taxonomy Presentation Linkbase Document

168

THE SOUTHERN COMPANY

SIGNATURES

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

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

Date: May 5, 2016

169

ALABAMA POWER COMPANY

SIGNATURES

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

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

Date: May 5, 2016

170

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, Treasurer, and Corporate Secretary
	(Principal Financial Officer)
By	/s/Melissa K. Caen
	(Melissa K. Caen, Attorney-in-fact)

Date: May 5, 2016

171

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.
	Chairman, President and Chief Executive Officer
	(Principal Executive Officer)
By	Xia Liu
	Vice President and Chief Financial Officer
	(Principal Financial Officer)
By	/s/Melissa K. Caen
	(Melissa K. Caen, Attorney-in-fact)

Date: May 5, 2016

172

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

Date: May 5, 2016

173

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

Date: May 5, 2016

174

EX-4.C3

Exhibit 4(c)3

Execution Version

Amendment No. 2 to Loan Guarantee Agreement

This Amendment No. 2 to Loan Guarantee Agreement, dated as of March 9, 2016 (this "Agreement"), is between Georgia Power Company, a corporation organized and existing under the laws of the State of Georgia (the "Borrower"), and the U.S. Department of Energy, an agency of the United States of America, acting by and through the Secretary of Energy (or appropriate authorized representative thereof) ("DOE").

WHEREAS, the Borrower and DOE have entered into that certain Loan Guarantee Agreement, dated as of February 20, 2014 (such agreement, as amended, amended and restated, restated, supplemented or otherwise modified from time to time, the "Loan Guarantee Agreement");

WHEREAS, the Borrower and DOE have entered into that certain Amendment No. 1 to Loan Guarantee Agreement, dated as of June 4, 2015;

WHEREAS, pursuant to that certain consent and waiver dated as of March 1, 2016, DOE consented to the Borrower's release of all ofThe Shaw Group Inc.'s obligations under the Shaw Guarantee pursuant to a general release and the termination of the Consent to Assignment, dated as of February 20, 2014, among The Shaw Group Inc., the Borrower, and the Collateral Agent; and

WHEREAS, the Borrower and DOE desire to amend the Loan Guarantee Agreement as provided below.

NOW, THEREFORE, in consideration of the mutual agreements herein contained and other good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged, the parties hereto, intending to be legally bound hereby, agree as follows:

Section 1. Definitions.

Capitalized terms used and not defined in this Agreement have the meanings provided in the Loan Guarantee Agreement. Unless otherwise indicated, all section references are to the Loan Guarantee Agreement.

Section 2. Amendments.

a.The Borrower and DOE by their respective signatures below hereby amend the Loan Guarantee Agreement by deleting the phrase ", The Shaw Group, Inc." from the following sections: Section 5.24(i)(i) (EPC Contractor), Section 6.11(d)(ii) (Prohibited Persons), Section 6.11(j) (OFAC) and Section 6.11(k) (Anti-Terrorism Order).

b.The Borrower and DOE by their respective signatures below hereby agree that from and after the execution and delivery of this Agreement, the Shaw Guarantee no longer will be considered a "Principal Project Document" or a "Project Document" and the Shaw Direct Agreement no longer will be considered a "Direct Agreement" or a "Loan Document", and thus neither the Shaw Guarantee nor the Shaw Direct Agreement will be considered a "Transaction Document".

Section 3. Representations and Warranties of Borrower.

Borrower by its signature below hereby represents and warrants, as of the date hereof, that:

a.it is a corporation, duly incorporated, validly existing and in good standing under the laws of the State of Georgia, and has all requisite corporate power and authority to execute, deliver, perform and observe the terms and conditions of this Agreement;

b.this Agreement is a legal, valid and binding obligation of the Borrower enforceable against the Borrower in accordance with its terms, subject to Bankruptcy Laws and general principles of equity, regardless of whether enforcement is considered in a proceeding at law or in equity; and

c.the Borrower has duly authorized, executed and delivered this Agreement, and neither its execution and delivery hereof nor its consummation of the transactions contemplated hereby nor its compliance with the terms hereof (i) contravenes its Organizational Documents, (ii) contravenes any Governmental Rules where such contravention would reasonably be expected to have a Material Adverse Effect or a material adverse effect on the ability of the Project to be completed, (iii) contravenes or results in any breach or constitutes any default under any Governmental Judgment, where such contravention, breach or default would reasonably be expected to have a Material Adverse Effect or material adverse effect on the ability of the Project to be completed, (iv) contravenes or results in any breach or constitutes any default under any agreement or instrument to which it is a party or by which it or any of its revenues, properties or assets may be bound, except where such contravention, breach or default would not reasonably be expected to have a Material Adverse Effect or a material adverse effect on the ability of the Project to be completed, (v) results in or requires the creation of any Lien upon any of its revenues, properties or assets, or (vi) requires the consent or approval of any Person which has not been obtained.

Section 4. Miscellaneous.

a.This Agreement is a Loan Document. The Loan Guarantee Agreement, as amended by this Agreement, is and shall continue to be in full force and effect and is hereby in all respects ratified.

b.This Agreement and the rights and obligations of the parties hereunder shall be governed by, and construed and interpreted in accordance with, the Federal law of the United

States of America. To the extent that Federal law does not specify the appropriate rule of decision for a particular matter at issue, it is the intention and agreement of the parties hereto that the law of the State of New York (without giving effect to its conflict of laws principles (except Section 5-1401 of the New York General Obligations Law)) shall be adopted as the governing Federal rule of decision.

c.This Agreement may be executed in any number of counterparts and by different parties in separate counterparts, each of which when so executed and delivered shall be deemed an original, but all of which counterparts together shall constitute but one and the same instrument.

d.Delivery of an executed counterpart of a signature page of this Agreement by telecopy or portable document format ("PDF") shall be effective as delivery of a manually executed counterpart of this Agreement.

[Remainder of page intentionally blank. Signature pages follow.]

IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be executed and delivered by their respective duly authorized officers or representatives as of the day and year first above written.

	U.S. DEPARTMENT OF ENERGY,
	as Guarantor
By:	/s/Robert C. Marcum
	Name:  Robert C. Marcum
	Title:  Director, Portfolio Management Division

[Amendment No. 2 to Loan Guarantee Agreement - Signature Page]

	Georgia Power Company,
	as Borrower
By:	/s/W. Ron Hinson
	Name:  W. Ron Hinson
	Title:  Executive Vice President,            Chief Financial Officer and Treasurer

[Amendment No. 2 to Loan Guarantee Agreement - Signature Page]

EX-4.E1

Exhibit 4(e)1

Closing Date Term Loan CUSIP Number: 60541GAB0

Delayed Draw Term Loan CUSIP Number: 60541GAC8

TERM LOAN AGREEMENT

among

MISSISSIPPI POWER COMPANY,

as Borrower,

THE LENDERS IDENTIFIED HEREIN,

BANK OF AMERICA, N.A.,

as Administrative Agent

and

MERRILL LYNCH, PIERCE, FENNER & SMITH INCORPORATED

and

MIZUHO BANK, LTD.,

as Joint Lead Arrangers and Joint Bookrunners

DATED AS OF March 8, 2016

TABLE OF CONTENTS

			Page
SECTION 1.   DEFINITIONS AND ACCOUNTING TERMS			1
	1.1	Definitions	1
	1.2	Computation of Time Periods and Other Definitional Provisions	13
	1.3	Accounting Terms	14
	1.4	[Reserved]	15
	1.5	Rounding Rates	15
SECTION 2.   LOANS			15
	2.1	Term Loan Commitment	16
	2.2	[Reserved]	16
	2.3	Extension of Maturity Date	16
	2.4	Method of Borrowing for Term Loans	16
	2.5	Funding of Term Loans	17
	2.6	Continuations and Conversions	17
	2.7	[Reserved]	17
	2.8	Reductions of Term Loan Commitment	17
	2.9	Evidence of Obligations	18
	2.10	[Reserved]	18
	2.11	[Reserved]	18
	2.12	[Reserved]	18
	2.13	Defaulting Lenders	18
SECTION 3.   PAYMENTS			19
	3.1	Interest	19
	3.2	Prepayments	20
	3.3	Payment in Full at Maturity	20
	3.4	Fees	20
	3.5	Place and Manner of Payments	20
	3.6	Pro Rata Treatment	21
	3.7	Computations of Interest and Fees	21
	3.8	Sharing of Payments	22
SECTION 4.   ADDITIONAL PROVISIONS REGARDING LOANS			23
	4.1	Eurodollar Loans	23
	4.2	Capital Adequacy	24
	4.3	Compensation	25
	4.4	Taxes	25
	4.5	Mitigation; Mandatory Assignment	28
SECTION 5.   CONDITIONS PRECEDENT			28
	5.1	Closing Conditions	28
	5.2	Conditions to Loans	30
SECTION 6.   REPRESENTATIONS AND WARRANTIES			30
	6.1	Organization and Good Standing	30

i

	6.2	Due Authorization	31
	6.3	No Conflicts	31
	6.4	Consents	31
	6.5	Enforceable Obligations	31
	6.6	Financial Condition	31
	6.7	No Default	31
	6.8	Indebtedness and Off Balance Sheet Indebtedness	31
	6.9	Litigation	32
	6.10	[Reserved]	32
	6.11	Taxes	32
	6.12	Compliance with Law	32
	6.13	ERISA	32
	6.14	Use of Proceeds; Margin Stock	33
	6.15	Investment Company Act	33
	6.16	Solvency	33
	6.17	OFAC	33
	6.18	Anti-Corruption Laws	33
	6.19	EEA Financial Institution	33
SECTION 7.   AFFIRMATIVE COVENANTS			33
	7.1	Information Covenants	34
	7.2	Preservation of Existence and Franchises	35
	7.3	Books and Records	35
	7.4	Compliance with Law	35
	7.5	Payment of Taxes	35
	7.6	Insurance	36
	7.7	Performance of Obligations	36
	7.8	ERISA	36
	7.9	Use of Proceeds	36
	7.10	Audits/Inspections	36
	7.11	Indebtedness to Capitalization	36
SECTION 8.   NEGATIVE COVENANTS			37
	8.1	Nature of Business	37
	8.2	Consolidation and Merger	37
	8.3	Sale or Lease of Assets	37
	8.4	Transactions with Affiliates	37
	8.5	Fiscal Year	38
	8.6	Liens	38
	8.7	Sanctions	39
	8.8	Anti-Corruption Laws	39
SECTION 9.   EVENTS OF DEFAULT			39
	9.1	Events of Default	39
	9.2	Acceleration; Remedies	41
	9.3	Allocation of Payments after Event of Default	42

ii

SECTION 10.   AGENCY PROVISIONS			42
	10.1	Appointment	42
	10.2	Delegation of Duties	43
	10.3	Exculpatory Provisions	43
	10.4	Reliance on Communications	44
	10.5	Notice of Default	44
	10.6	Non-Reliance on Administrative Agent and Other Lenders	44
	10.7	Indemnification	45
	10.8	Administrative Agent in Its Individual Capacity	45
	10.9	Successor Administrative Agent	45
	10.10	Administrative Agent May File Proof of Claims	46
SECTION 11.   MISCELLANEOUS			47
	11.1	Notices and other Communications; Facsimile Copies	47
	11.2	Right of Set-Off	49
	11.3	Benefit of Agreement	49
	11.4	No Waiver; Remedies Cumulative	52
	11.5	Payment of Expenses, etc	52
	11.6	Amendments, Waivers and Consents	53
	11.7	Counterparts; Telecopy	54
	11.8	Headings	54
	11.9	[Reserved]	54
	11.10	Survival of Indemnification and Representations and Warranties	54
	11.11	Governing Law; Jurisdiction	55
	11.12	Waiver of Jury Trial; Waiver of Consequential Damages	55
	11.13	Time	56
	11.14	Severability	56
	11.15	Entirety	56
	11.16	Confidentiality	56
	11.17	Binding Effect	57
	11.18	USA Patriot Act Notice	57
	11.19	No Fiduciary Responsibility	58
	11.20	Acknowledgment and Consent to Bail-In of EEA Financial Institutions	58

iii

SCHEDULES

Schedule 1.1(a)	Commitment Percentages
Schedule 1.1(b)	Existing Term Loan Agreements
Schedule 11.1	Notices
EXHIBITS
Exhibit 2.4	Form of Notice of Borrowing of Term Loans
Exhibit 2.6	Form of Notice of Continuation/Conversion
Exhibit 2.9(a)	Form of Closing Date Term Loan Note
Exhibit 2.9(b)	Form of Delayed Draw Term Loan Note
Exhibit 7.1(c)	Form of Compliance Certificate
Exhibit 11.3(b)	Form of Assignment and Assumption

iv

TERM LOAN AGREEMENT

THIS TERM LOAN AGREEMENT (this “Term Loan Agreement”), dated as of March 8, 2016, is entered into among MISSISSIPPI POWER COMPANY, a Mississippi corporation (the “Borrower”), the Lenders (as defined herein) and BANK OF AMERICA, N.A., as administrative agent for the Lenders (in such capacity, the “Administrative Agent”).

RECITALS

WHEREAS, the Borrower has requested that the Lenders provide term loan credit facilities, and the Lenders are willing to do so on the terms and conditions set forth herein.

WHEREAS, Merrill Lynch, Pierce, Fenner & Smith Incorporated and Mizuho Bank, Ltd. are acting as Joint Lead Arrangers and Joint Bookrunners in connection with this Term Loan Agreement.

NOW, THEREFORE, IN CONSIDERATION of the premises and other good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged, the parties hereto agree as follows:

SECTION 1.

DEFINITIONS AND ACCOUNTING TERMS

1.1  Definitions.

As used herein, the following terms shall have the meanings herein specified unless the context otherwise requires. Defined terms herein shall include in the singular number the plural and in the plural the singular:

“Adjusted Base Rate” means the Base Rate plus the Applicable Percentage for Base Rate Loans.

“Adjusted Eurodollar Rate” means the Eurodollar Rate plus the Applicable Percentage for Eurodollar Loans.

“Administrative Agent’s Office” means the Administrative Agent’s address and, as appropriate, account as set forth on Schedule 11.1 or such other address or account as the Administrative Agent may from time to time notify to the Borrower and the Lenders.

“Administrative Questionnaire” means an Administrative Questionnaire in a form supplied by the Administrative Agent.

“Affiliate” means, with respect to any Person, any other Person directly or indirectly controlling (including but not limited to all directors and officers of such Person), controlled by or under direct or indirect common control with such Person. A Person shall be deemed to control a corporation if such Person possesses, directly or indirectly, the power (i) to vote 20% or more of the securities having ordinary voting power for the election of directors of such corporation or (ii) to direct or cause direction of the management and policies of such corporation, whether through the ownership of voting securities, by contract or otherwise.

“Agent-Related Persons” means the Administrative Agent (including any successor administrative agent), together with its Affiliates, and the officers, directors, employees, representatives, agents, counsel and attorneys-in-fact of such Persons and Affiliates.

“Applicable Percentage” means, at any time, and with respect to all Eurodollar Loans, Base Rate Loans and Unused Fees, the applicable percentage corresponding to the Senior Debt Rating in effect from time to time as described below:

Senior Debt Rating	Applicable Percentage for Eurodollar Loans	Applicable Percentage for Base Rate Loans	Applicable Percentage for Unused Fees
I.       ≥ A+ from S&P ≥A1 from Moody’s ≥A+ from Fitch	1.125%	0.125%	0.075%
II.     ≥ A but < A+ from S&P ≥A2 but < A1 from Moody’s ≥A but < A+ from Fitch	1.250%	0.250%	0.100%
III.    ≥ A‑ but < A from S&P ≥A3 but < A2 from Moody’s ≥A‑ but < A from Fitch	1.375%	0.375%	0.125%
IV.    ≥ BBB+ but < A‑ from S&P ≥Baa1 but < A3 from Moody’s ≥BBB+ but < A‑ from Fitch	1.500%	0.500%	0.175%
V.     ≥ BBB but < BBB+ from S&P ≥Baa2 but < Baa1 from Moody’s ≥BBB but < BBB+ from Fitch	1.750%	0.750%	0.225%
VI.    < BBB- from S&P < Baa3 from Moody’s < BBB- from Fitch or unrated by any two of S&P, Moody’s or Fitch	2.000%	1.000%	0.275%

Notwithstanding the above, if at any time there is a split in Senior Debt Ratings among S&P, Moody’s and Fitch and (a) two Senior Debt Ratings are equal and higher than the third

2

Senior Debt Rating, the higher Senior Debt Ratings will apply, (b) two Senior Debt Ratings are equal and lower than the third Senior Debt Rating, the lower Senior Debt Ratings will apply or (c) no Senior Debt Ratings are equal, the intermediate Senior Debt Rating will apply. In the event that the Borrower shall maintain Senior Debt Ratings from only two of S&P, Moody’s or Fitch and there is a split in such Senior Debt Ratings, (i) in the event of a single level split, the higher Senior Debt Rating (i.e. the lower pricing) will apply and (ii) in the event of a multiple level split, one level below the higher Senior Debt Rating will apply.

The Applicable Percentages for Eurodollar Loans, Base Rate Loans and Unused Fees shall be determined and adjusted on the date (each a “Calculation Date”) on which there is any change in the Senior Debt Rating of the Borrower. Each Applicable Percentage shall be effective from one Calculation Date until the next Calculation Date. Any adjustment in the Applicable Percentage shall be applicable to all existing Loans as well as any new Loans made. The Borrower shall notify the Administrative Agent in writing immediately upon any change in its Senior Debt Rating.

“Approved Fund” means any Fund that is administered or managed by (a) a Lender, (b) an Affiliate of a Lender or (c) an entity or an Affiliate of an entity that administers or manages a Lender.

“Arrangers” means MLPF&S and Mizuho.

“Assignment and Assumption” means an assignment and assumption entered into by a Lender and an Eligible Assignee (with the consent of any party whose consent is required by Section 11.3(b), and accepted by the Administrative Agent, in substantially the form of Exhibit 11.3(b) or any other form (including electronic documentation generated by use of an electronic platform) approved by the Administrative Agent).

“Bail-In Action” means the exercise of any Write-Down and Conversion Powers by the applicable EEA Resolution Authority in respect of any liability of an EEA Financial Institution.

“Bail-In Legislation” means, with respect to any EEA Member Country implementing Article 55 of Directive 2014/59/EU of the European Parliament and of the Council of the European Union, the implementing law for such EEA Member Country from time to time which is described in the EU Bail-In Legislation Schedule.

“Bankruptcy Code” means the Bankruptcy Code in Title 11 of the United States Code, as amended, modified, succeeded or replaced from time to time.

“Base Rate” means, for any day, a simple rate per annum equal to the greatest of (a) the Prime Rate for such day, (b) the sum of 1/2% plus the Federal Funds Rate for such day and (c) the one month Eurodollar Rate plus1.0%; and if the Base Rate shall be less than zero, such rate shall be deemed zero for purposes of this Agreement.

“Base Rate Loan” means a Term Loan which bears interest based on the Adjusted Base Rate.

“Borrower” means Mississippi Power Company, a Mississippi corporation, or such other Person as may become the Borrower pursuant to Section 8.2(b)(ii), and its successors.

3

“Borrower Obligations” means, without duplication, all of the obligations of the Borrower to the Lenders and the Administrative Agent, whenever arising, under this Term Loan Agreement, any Notes or any of the other Credit Documents.

“Business Day” means any day other than a Saturday, a Sunday, a legal holiday or a day on which any Lender specifically or banking institutions generally are authorized or required by law or other governmental action to close in Charlotte, North Carolina or New York, New York; provided that in the case of Eurodollar Loans, such day is also a day on which dealings between banks are carried on in Dollar deposits in the London interbank market.

“Calculation Date” has the meaning set forth in the definition of Applicable Percentage.

“Capitalization” means, with respect to the Borrower and its consolidated Subsidiaries (determined on a consolidated basis), without duplication, the sum of (a) the aggregate of (i) the capital stock (but excluding treasury stock and capital stock subscribed and unissued), other equity accounts (including retained earnings and paid‑in capital, but excluding accumulated other comprehensive income and loss) of the Borrower and its Subsidiaries as the same appears on its balance sheet prepared in accordance with GAAP as of the date of determination and (ii)the principal amount of Hybrid Securities (other than Hybrid Securities that are Indebtedness) and (b) the amount of all Indebtedness of the Borrower and its Subsidiaries as of the same date.

“Change of Control” means the failure of The Southern Company, a Delaware corporation, to own more than 51% of the outstanding shares of the capital stock of the Borrower entitled to vote generally for the election of directors of the Borrower.

“Closing Date” means the date hereof.

“Closing Date Term Loan Commitment” means, with respect to each Lender, such Lender’s Closing Date Term Loan Commitment as set forth on Schedule 1.1(a) attached hereto (based on such Lender’s Closing Date Term Loan Commitment Percentage of the Closing Date Term Loan Commitment) and “Closing Date Term Loan Commitments” means, collectively, the sum of all such Lenders’ Commitments, which, as of the Closing Date is an aggregate amount equal to NINE HUNDRED MILLION DOLLARS ($900,000,000).

“Closing Date Term Loan Commitment Percentage” means, for each Lender, the percentage identified as its Closing Date Term Loan Commitment Percentage opposite such Lender’s name on Schedule 1.1(a) attached hereto, as such percentage may be modified by assignment in accordance with Section 11.3 or Section 2.13 of this Term Loan Agreement.

“Closing Date Term Loan Notes” means the promissory notes of the Borrower in favor of each Lender requesting such notes evidencing the Closing Date Term Loans and substantially in the form of Exhibit 2.9(a), as such promissory notes may be amended, modified, supplemented or replaced from time to time.

“Closing Date Term Loans” has the meaning set forth in Section 2.1(a).

“Code” means the Internal Revenue Code of 1986, as amended from time to time.

“Commitment” means, with respect to each Lender, such Lender’s Closing Date Term Loan Commitment or Delayed Draw Term Loan Commitment, as applicable, and

4

“Commitments” means, collectively, the sum of all such Lenders’ Closing Date Term Loan Commitments and Delayed Draw Term Loan Commitments.

“Commitment Percentage” means, with respect to each Lender, such Lender’s Closing Date Term Loan Commitment Percentage or Delayed Draw Term Loan Commitment Percentage, as applicable.

“Credit Documents” means this Term Loan Agreement, any Notes and all other related agreements and documents issued or delivered hereunder or thereunder or pursuant hereto or thereto.

“Debt Rating” means any credit rating of the Borrower by S&P, Moody’s or Fitch.

“Debtor Relief Laws” means the Bankruptcy Code of the United States and all other liquidation, conservatorship, bankruptcy, assignment for the benefit of creditors, moratorium, rearrangement, receivership, insolvency, reorganization or similar debtor relief Laws of the United States or other applicable jurisdictions from time to time in effect and affecting the rights of creditors generally.

“Delayed Draw Term Loan Commitment” means, with respect to each Lender, such Lender’s Delayed Draw Term Loan Commitment as set forth on Schedule 1.1(a) attached hereto (based on such Lender’s Delayed Draw Term Loan Commitment Percentage of the Delayed Draw Term Loan Commitment) and “Delayed Draw Term Loan Commitments” means, collectively, the sum of all such Lenders’ Commitments, which, as of the Closing Date is an aggregate amount equal to THREE HUNDRED MILLION DOLLARS ($300,000,000).

“Delayed Draw Term Loan Commitment Percentage” means, for each Lender, the percentage identified as its Delayed Draw Term Loan Commitment Percentage opposite such Lender’s name on Schedule 1.1(a) attached hereto, as such percentage may be modified by assignment in accordance with Section 11.3 or Section 2.13 of this Term Loan Agreement.

“Delayed Draw Term Loan Notes” means the promissory notes of the Borrower in favor of each Lender requesting such notes evidencing the Delayed Draw Term Loans and substantially in the form of Exhibit 2.9(b), as such promissory notes may be amended, modified, supplemented or replaced from time to time.

“Delayed Draw Term Loans” has the meaning set forth in Section 2.1(b).

“Default” means any event, act or condition which, with notice or lapse of time, or both, would constitute an Event of Default.

“Defaulting Lender” means, subject to Section 2.13(b), any Lender that (a) has failed to (i) fund all or any portion of its Loans within two (2) Business Days of the date such Loans were required to be funded hereunder unless such Lender notifies the Administrative Agent and the Borrower in writing that such failure is the result of such Lender’s good faith determination that one or more conditions precedent to funding (each of which conditions precedent, together with any applicable default, shall be specifically identified in such writing) has not been satisfied or (ii) pay, within two (2) Business Days of the date such payment was required to be made, to the Administrative Agent or any other Lender any other amount required to be paid by it hereunder, (b) has notified the Borrower or the Administrative Agent in writing that it does not intend to comply with its funding obligations hereunder, or has made a public statement to that effect

5

(unless such writing or public statement relates to such Lender’s obligation to fund a Loan hereunder and states that such position is based on such Lender’s determination that a condition precedent to funding (which condition precedent, together with any applicable default, shall be specifically identified in such writing or public statement) cannot be satisfied), (c) has failed, within three (3) Business Days after request by the Administrative Agent or the Borrower, to confirm in writing to the Administrative Agent and the Borrower that it will comply with its prospective funding obligations hereunder (provided that such Lender shall cease to be a Defaulting Lender pursuant to this clause (c) upon receipt of such written confirmation by the Administrative Agent and the Borrower), or (d) has, or has a direct or indirect parent company that has, (i) become the subject of a proceeding under any Debtor Relief Law, (ii) had appointed for it a receiver, custodian, conservator, trustee, administrator, assignee for the benefit of creditors or similar Person charged with reorganization or liquidation of its business or assets, including the Federal Deposit Insurance Corporation or any other state or federal regulatory authority acting in such capacity, or (iii) become the subject of a Bail-In Action; provided that a Lender shall not be a Defaulting Lender solely by virtue of the ownership or acquisition of any equity interest in that Lender or any direct or indirect parent company thereof by a Governmental Authority so long as such ownership interest does not result in enforcement of judgments or writs of attachment on its assets or permit such Lender (or such Governmental Authority) to reject, repudiate, disavow or disaffirm any contracts or agreements made with such Lender. Any determination by the Administrative Agent that a Lender is a Defaulting Lender under clauses (a) through (d) above shall be conclusive and binding absent manifest error, and such Lender shall be deemed to be a Defaulting Lender (subject to Section 2.13(b)) upon delivery of written notice of such determination to the Borrower and each Lender.

“Default Rate” means an interest rate equal to the interest rate (including the Applicable Percentage, if any) otherwise applicable to such Borrower Obligations plus 2% per annum.

“Designated Jurisdiction” means any country or territory to the extent that such country or territory itself is the subject of any Sanction.

“Dollars” and “$” means dollars in lawful currency of the United States of America.

“EEA Financial Institution” means (a) any credit institution or investment firm established in any EEA Member Country which is subject to the supervision of an EEA Resolution Authority, (b) any entity established in an EEA Member Country which is a parent of an institution described in clause (a) of this definition, or (c) any financial institution established in an EEA Member Country which is a subsidiary of an institution described in clauses (a) or (b) of this definition and is subject to consolidated supervision with its parent.

“EEA Member Country” means any of the member states of the European Union, Iceland, Liechtenstein, and Norway.

“EEA Resolution Authority” means any public administrative authority or any person entrusted with public administrative authority of any EEA Member Country (including any delegee) having responsibility for the resolution of any EEA Financial Institution.

“Eligible Assignee” means (a) an existing Lender; (b) Affiliates of an existing Lender; (c) an Approved Fund; and (d) any other Person (other than a natural Person) that (i) unless an Event of Default has occurred and is continuing, has a combined capital and surplus of at least $5,000,000,000 and (ii) is approved by (A) the Administrative Agent and (B) unless a Default or Event of Default has occurred and is continuing, the Borrower (each such approval not to be

6

unreasonably withheld or delayed); provided that (x) the Borrower’s failure to respond within ten (10) days of receipt of written notice of such assignment shall be deemed to be Borrower’s approval thereof and (y) notwithstanding the foregoing, “Eligible Assignee” shall not include the Borrower or any of the Borrower’s Affiliates or Subsidiaries.

“ERISA” means the Employee Retirement Income Security Act of 1974, as amended from time to time, and the regulations promulgated and the rulings issued thereunder.

“ERISA Affiliate” means any trade or business (whether or not incorporated) under common control with the Borrower within the meaning of Section 414(b) or (c) of the Code (and Sections 414(m) and (o) of the Code for purposes of provisions relating to Section 412 of the Code).

“ERISA Event” means (a) a Reportable Event with respect to a Pension Plan; (b) the withdrawal of the Borrower or any ERISA Affiliate from a Pension Plan subject to Section 4063 of ERISA during a plan year in which the Borrower or any ERISA Affiliate was a substantial employer (as defined in Section 4001(a)(2) of ERISA) or the Borrower or any ERISA Affiliate incurred a cessation of operations that is treated as such a withdrawal under Section 4062(e) of ERISA; (c) a complete or partial withdrawal by the Borrower or any ERISA Affiliate from a Multiemployer Plan or receipt by the Borrower or any ERISA Affiliate of notice from the Multiemployer Plan that the Multiemployer Plan is in critical or endangered status, in reorganization or insolvent; (d) the filing by the Borrower or any ERISA Affiliate of a notice of intent to terminate a Pension Plan under a distress termination under Section 4041 of ERISA, (e) receipt by Borrower or any ERISA Affiliate of notice from the PBGC of the institution by the PBGC of proceedings to terminate a Pension Plan; (f) receipt by the Borrower or any ERISA Affiliate of notice from the PBGC of the appointment of a trustee to administer a Pension Plan; (g) the determination by an actuary for the Pension Plan that the Pension Plan is considered an at-risk plan within the meaning of Section 430 of the Code or Section 303 of ERISA or (h) the imposition of any liability under Title IV of ERISA, other than for PBGC premiums due but not delinquent under Section 4007 of ERISA and claims for benefit and funding obligations in the ordinary course, upon the Borrower or any ERISA Affiliate.

“EU Bail-In Legislation Schedule” means the EU Bail-In Legislation Schedule published by the Loan Market Association (or any successor person), as in effect from time to time.

“Eurodollar Loan” means a Term Loan bearing interest based on the Adjusted Eurodollar Rate.

“Eurodollar Base Rate” means:

(a)for any Interest Period with respect to a Eurodollar Loan, the rate per annum equal to the London Interbank Offered Rate (“LIBOR”) or a comparable or successor rate, which rate is approved by the Administrative Agent, as published by Bloomberg (or such other commercially available source providing such quotations as may be designated by the Administrative Agent from time to time) (in such case, the “LIBOR Rate”) at approximately 11:00 a.m., London time, two Business Days prior to the commencement of such Interest Period, for Dollar deposits (for delivery on the first day of such Interest Period) with a term equivalent to such Interest Period; and

(b)for any interest calculation with respect to a Base Rate Loan on any date, the rate per annum equal to the LIBOR Rate, at approximately 11:00 a.m., London time

7

determined two Business Days prior to such date for Dollar deposits with a term of one month commencing that day;

provided that (i) to the extent a comparable or successor rate is approved by the Administrative Agent in connection herewith, the approved rate shall be applied in a manner consistent with market practice; provided, further that to the extent such market practice is not administratively feasible for the Administrative Agent, such approved rate shall be applied as otherwise reasonably determined by the Administrative Agent and (ii) if the Eurodollar Base Rate shall be less than zero, such rate shall be deemed zero for purposes of this Agreement.

“Eurodollar Rate” means (a) for any Interest Period with respect to any Eurodollar Loan, a rate per annum determined by the Administrative Agent to be equal to the quotient obtained by dividing (i) the Eurodollar Base Rate for such Eurodollar Loan for such Interest Period by (ii) one minus the Eurodollar Reserve Percentage for such Eurodollar Loan for such Interest Period and (b) for any day with respect to any Base Rate Loan the interest rate on which is determined by reference to the Eurodollar Rate, a rate per annum determined by the Administrative Agent to be equal to the quotient obtained by dividing (i) the Eurodollar Base Rate for such Base Rate Loan for such day by (ii) one minus the Eurodollar Reserve Percentage for such Base Rate Loan for such day.

“Eurodollar Reserve Percentage” means for any day, that percentage (expressed as a decimal) which is in effect from time to time under Regulation D, as the maximum reserve requirement (including, without limitation, any basic, supplemental, emergency, special, or marginal reserves) applicable with respect to “Eurocurrency liabilities” as that term is defined in Regulation D (or against any other category of liabilities that includes deposits by reference to which the interest rate of Eurodollar Loans is determined), whether or not any Lender has any Eurodollar liabilities subject to such reserve requirement at that time. Eurodollar Loans shall be deemed to constitute Eurodollar liabilities and as such shall be deemed subject to reserve requirements without benefits of credits for proration, exceptions or offsets that may be available from time to time to a Lender. The Eurodollar Rate shall be adjusted automatically on and as of the effective date of any change in the Eurodollar Reserve Percentage.

“Event of Default” has the meaning specified in Section 9.1.

“Existing Term Loan Agreements” means those agreements set forth on Schedule 1.1(b).

“FATCA” means Sections 1471 through 1474 of the Code, as of the date of this Term Loan Agreement (or any amended or successor version that is substantively comparable and not materially more onerous to comply with), and any regulations promulgated thereunder or official interpretations thereof, any agreements entered into pursuant to Section 1471(b)(1) of the Code and any applicable intergovernmental agreements implementing the foregoing.

“Federal Funds Rate” means for any day the rate per annum (rounded upward to the nearest 1/100th of 1%) equal to the weighted average of the rates on overnight Federal funds transactions with members of the Federal Reserve System, as published by the Federal Reserve Bank of New York on the Business Day next succeeding such day; provided that (a) if such day is not a Business Day, the Federal Funds Rate for such day shall be such rate on such transactions on the next preceding Business Day as so published on the next succeeding Business Day and (b) if no such rate is so published on such next succeeding Business Day, the Federal Funds Rate

8

for such day shall be the average rate quoted to the Administrative Agent on such day on such transactions as determined by the Administrative Agent.

“Fee Letters” means, collectively (a) that certain letter agreement, dated as of February 9, 2016, among the Borrower, Bank of America, N.A. and MLPF&S and (b) that certain letter agreement, dated as of February 9, 2016, between the Borrower and Mizuho (each a “Fee Letter”).

“Fitch” means Fitch Ratings, Inc., or any successor or assignee of the business of such company in the business of rating securities.

“Fund” shall mean any Person (other than a natural Person) that is, or will be, engaged in making, purchasing, holding or otherwise investing in commercial loans and similar extensions of credit in the ordinary course of its business.

“GAAP” means generally accepted accounting principles in the United States applied on a consistent basis and subject to Section 1.3.

“Governmental Authority” means any Federal, state, local or foreign court or governmental agency, authority, instrumentality or regulatory body, court, central bank or other entity exercising executive, legislative, judicial, taxing, regulatory or administrative powers or functions of or pertaining to government (including any supra-national bodies such as the European Union or the European Central Bank).

“Guaranty Obligations” means, in respect of any Person, any legally enforceable obligation, contingent or otherwise, of such Person directly or indirectly guaranteeing any Indebtedness of another Person.

“Hybrid Securities” means (a) any Trust Preferred Obligations and any Junior Subordinated Deferred Interest Debt Obligations and (b) any other securities of the Borrower (other than capital stock of the Borrower) that are afforded equity treatment by any rating agency at the time of issuance of such securities.

“Indebtedness” means, as to any Person, without duplication: (a) all obligations of such Person for borrowed money or evidenced by bonds, debentures, notes or similar instruments, including, without limitation, the obligations of such Person under the SCFC Notes; (b) all obligations of such Person for the deferred purchase price of property or services (except trade accounts payable arising in the ordinary course of business); (c) all capital lease obligations of such Person; (d) all Indebtedness of others secured by a Lien on any properties, assets or revenues of such Person (other than stock, partnership interests or other equity interests of such Person in entities other than the Borrower or any of its Subsidiaries) to the extent of the lesser of the value of the property subject to such Lien or the amount of such Indebtedness; (e) all Guaranty Obligations; and (f) all non-contingent obligations of such Person under any letters of credit or bankers' acceptances.

It is understood and agreed for purposes of calculations under Section 7.11 of this Agreement that Indebtedness (including Guaranty Obligations) shall not include (A) any indebtedness with respect to Rate Reduction Bonds to the extent such Indebtedness is non-recourse to the Borrower, (B) any Off Balance Sheet Indebtedness in existence as of the Closing Date and additional Off Balance Sheet Indebtedness in an amount not to exceed $250,000,000 in the aggregate at any time, other than obligations of any partnership or joint venture that are recourse to the Borrower

9

or any of its Subsidiaries, (C) any refinancing of Off Balance Sheet Indebtedness described in subsection (B) above in a principal amount not in excess of that outstanding as of the date of refinancing, (D) [reserved] or (E) any Indebtedness with respect to Hybrid Securities, as long as (1) the maturity date of such Hybrid Securities is subsequent to the Maturity Date, and (2) such Hybrid Securities are fully subordinated in right of payment to the Borrower Obligations; provided that the aggregate amount of Hybrid Securities excluded for purposes of calculation of Section 7.11 at any date shall not exceed 15% of Capitalization; and providedfurther, that the amount of any mandatory principal amortization or defeasance of Hybrid Securities prior to the Maturity Date and any Hybrid Securities with a maturity date prior to the Maturity Date shall, in each case, be included in this definition of Indebtedness.

“Interest Payment Date” means (a) as to Base Rate Loans, the last day of each fiscal quarter of the Borrower and the Maturity Date and (b) as to Eurodollar Loans, the last day of each applicable Interest Period and the Maturity Date. In addition, where the applicable Interest Period for a Eurodollar Loan is greater than three months, then an Interest Payment Date shall also occur on the last day of each three‑month period during such Interest Period. If an Interest Payment Date falls on a date which is not a Business Day, such Interest Payment Date shall be deemed to be the next succeeding Business Day, except that in the case of Eurodollar Loans where the next succeeding Business Day falls in the next succeeding calendar month, then on the next preceding Business Day.

“Interest Period” means, as to Eurodollar Loans, a period of one, two, three or six months’ duration or such other periods as agreed to by all Lenders, as the Borrower may elect and as may be available, commencing, in each case, on the date of the borrowing (including continuations and conversions of Eurodollar Loans); provided, however, (i) if any Interest Period would end on a day which is not a Business Day, such Interest Period shall be extended to the next succeeding Business Day (except that where the next succeeding Business Day falls in the next succeeding calendar month, then on the next preceding Business Day), (ii) no Interest Period shall extend beyond the Maturity Date and (iii) with respect to Eurodollar Loans, where an Interest Period begins on a day for which there is no numerically corresponding day in the calendar month in which the Interest Period is to end, such Interest Period shall end on the last Business Day of such calendar month.

“Junior Subordinated Deferred Interest Debt Obligations” means subordinated deferrable interest debt obligations of the Borrower or one of its Subsidiaries.

“Laws” means, collectively, all international, foreign, Federal, state and local statutes, treaties, rules, guidelines, regulations, ordinances, codes and administrative or judicial precedents or authorities, including the interpretation or administration thereof by any Governmental Authority charged with the enforcement, interpretation or administration thereof, and all applicable administrative orders, directed duties, requests, licenses, authorizations and permits of, and agreements with, any Governmental Authority, in each case whether or not having the force of law.

“Lenders” means those banks and other financial institutions identified as such on the signature pages hereto and such other institutions that may become Lenders pursuant to Section 11.3.

“Lien” means any mortgage, pledge, hypothecation, assignment, deposit arrangement, security interest, encumbrance, lien (statutory or otherwise), preference, priority or charge of any kind (including any agreement to give any of the foregoing, any conditional sale or other title

10

retention agreement, any financing or similar statement or notice filed under the Uniform Commercial Code as adopted and in effect in the relevant jurisdiction or other similar recording or notice statute, and any lease in the nature thereof).

“Loans” means the Term Loans.

“Material Adverse Effect” means a material adverse effect on (a) the operations, assets, financial condition or business of the Borrower, (b) the ability of the Borrower to perform its obligations under this Term Loan Agreement and the other Credit Documents or (c) the validity or enforceability of this Term Loan Agreement, any of the other Credit Documents, or the rights and remedies of the Lenders hereunder or thereunder; provided, that neither a downgrade in any Debt Rating nor the inability of the Borrower to place commercial paper or variable rate tax exempt pollution control bonds shall, in and of itself, constitute a Material Adverse Effect.

“Maturity Date” means April 1, 2018; provided that if the Maturity Date as determined hereunder falls on a day that is not a Business Day, such Maturity Date shall be deemed to fall on the next preceding Business Day.

“Mizuho” means Mizuho Bank Ltd..

“MLPF&S” means Merrill Lynch, Pierce, Fenner & Smith Incorporated.

“Moody’s” means Moody’s Investors Service, Inc., or any successor or assignee of the business of such company in the business of rating securities.

“Multiemployer Plan” means any employee benefit plan of the type described in Section 4001(a)(3) of ERISA, to which the Borrower or any ERISA Affiliate makes or is obligated to make contributions, or has any continuing liability.

“Net Tangible Assets” means, as of any date, the total assets shown on the balance sheet of the Borrower and its Subsidiaries, determined on a consolidated basis in accordance with GAAP less (a) all current liabilities and minority interests and (b) goodwill and other identifiable intangibles.

“Non-Consenting Lender” has the meaning set forth in Section 4.5.

“Non-Defaulting Lender” means, at any time, each Lender that is not a Defaulting Lender at such time.

“Notes” means any Closing Date Term Loan Notes and/or Delayed Draw Term Loan Notes.

“Notice of Borrowing of Term Loans” means a request by the Borrower for a Term Loan (or any continuation or conversion thereof) in substantially the form of Exhibit 2.4 or such other form as may be approved by the Administrative Agent (including any form on an electronic platform or electronic transmission system as shall be approved by the Administrative Agent) appropriately completed and signed by a Responsible Officer of the Borrower.

“Notice of Continuation/Conversion” means a request by the Borrower for the continuation or conversion of a Term Loan in the form of Exhibit 2.6.

11

“OFAC” means the Office of Foreign Assets Control of the United States Department of the Treasury.

“Off Balance Sheet Indebtedness” means any obligation of a Person that would be considered indebtedness for tax purposes but is not set forth on the balance sheet of such Person, including, but not limited to, (a) any synthetic lease, tax retention operating lease, off balance sheet loan or similar off‑balance sheet financing product of such Person, (b) the aggregate amount of uncollected accounts receivables of such Person subject at such time to a sale of receivables (or similar transaction) and (c) obligations of any partnership or joint venture that is recourse to such Person.

“Other Taxes” has the meaning set forth in Section 4.4(b).

“Participation Purchaser” shall have the meaning assigned to such term in Section 11.3(d).

“PBGC” means the Pension Benefit Guaranty Corporation or any successor thereto.

“Pension Act” means the Pension Protection Act of 2006.

“Pension Funding Rules” means the rules of the Code and ERISA regarding minimum required contributions (including any installment payment thereof) to Pension Plans and set forth in, with respect to plan years ending prior to the effective date of the Pension Act, Section 412 of the Code and Section 302 of ERISA, each as in effect prior to the Pension Act and, thereafter, Section 412, 430, and 436 of the Code and Sections 302 and 303 of ERISA.

“Pension Plan” means any “employee pension benefit plan”, as defined in Section 3(2) of ERISA (other than a Multiemployer Plan) that is maintained, contributed to or required to be contributed to by the Borrower and any ERISA Affiliate and is either covered by Title IV of ERISA or is subject to the minimum funding standards under Section 412 of the Code.

“Person” means any individual, partnership (general or limited), limited liability company, joint venture, firm, corporation, association, trust or other enterprise (whether or not incorporated), or any government or political subdivision or any agency, department or instrumentality thereof.

“Prime Rate” means the per annum rate of interest established from time to time by the Administrative Agent at the Administrative Agent’s Office as its “prime rate”. Such rate is a rate set by the Administrative Agent based upon various factors including the Administrative Agent’s costs and desired return, general economic conditions and other factors, and is used as a reference point for pricing some loans, which may be priced at, above or below such announced rate. Any change in the interest rate resulting from a change in the Prime Rate shall become effective as of the opening of business on the day on which such change in the Prime Rate is announced by the Administrative Agent.

“Rate Reduction Bonds” means any bonds, debentures, notes, certificates of participation, certificates of beneficial interest, certificates of ownership or other evidences of Indebtedness or ownership that are issued by the Borrower, any entity formed by the Borrower or an assignee pursuant to an order of the Mississippi Public Service Commission under legislation passed by the legislature of the State of Mississippi, including, but not limited to, the Mississippi Public Utility Rate Mitigation and Reduction Act, the proceeds of which are used directly or indirectly to

12

recover, finance or refinance generation facility costs and financing costs, and which are secured by or payable from all rights and interests of the Borrower or its Subsidiaries or successor or assignee under the applicable rate reduction bond financing order, including the right to impose, bill, collect and receive rate reduction bond charges, the right to obtain periodic adjustments to such charges as provided in the applicable rate reduction bond financing order and rights in any other security property included in the applicable rate reduction bond financing order.

“Regulation D, U or X” means Regulation D, U or X, respectively, of the Board of Governors of the Federal Reserve System as from time to time in effect and any successor to all or a portion thereof.

“Reportable Event” means a “reportable event” as defined in Section 4043(c) of ERISA with respect to which the notice requirements to the PBGC have not been waived.

“Required Lenders” means Lenders whose aggregate Credit Exposure (as hereinafter defined) constitutes more than 50% of the aggregate Credit Exposure of all Lenders at such time. For purposes of the preceding sentence, the term “Credit Exposure” as applied to each Lender shall mean (a) at any time prior to the termination of the Commitments, an amount equal to the Commitment of such Lender and (b) at any time after the termination of the Commitments, the outstanding amount of Term Loans owed to such Lender.

“Responsible Officer” means, as to the Borrower, any of the Chief Executive Officer, Chief Financial Officer, Treasurer, Comptroller, Secretary, Assistant Treasurer or Assistant Secretary of the Borrower and, solely for purposes of notices given pursuant to Article II, any other officer or employee of the Borrower so designated by any of the foregoing officers in a notice to the Administrative Agent.

“Sanction(s)” means any economic or financial sanction administered or enforced by the United States Government, including, without limitation, OFAC, the United Nations Security Council, the European Union or Her Majesty’s Treasury (“HMT”).

“S&P” means Standard & Poor’s Financial Services LLC, a division of McGraw‑Hill Financial and any successor thereto.

“SCFC” means Southern Company Funding Corporation, a Delaware corporation, an Affiliate of the Borrower and a wholly-owned Subsidiary of The Southern Company, a Delaware corporation.

“SCFC Notes” means one or more intercompany notes issued by the Borrower to SCFC in support of commercial paper issued by SCFC on behalf of the Borrower pursuant to that certain Financial Services Agreement, dated as of March 15, 2001, between the Borrower and SCFC.

“Senior Debt Rating” means the long-term senior unsecured, non-credit enhanced debt rating of the Borrower by each of S&P, Moody’s or Fitch.

“Significant Subsidiary” means a Subsidiary of the Borrower which represents more than 15% of the Borrower’s assets on a consolidated basis.

“Subsidiary” means, as to any Person, (a) any corporation more than 50% of whose stock of any class or classes having by the terms thereof ordinary voting power to elect a majority of

13

the directors of such corporation (irrespective of whether or not at the time, any class or classes of such corporation shall have or might have voting power by reason of the happening of any contingency) is at the time owned by such Person directly or indirectly through Subsidiaries and (b) any partnership, limited liability company, association, joint venture or other entity in which such Person directly or indirectly through Subsidiaries has more than 50% equity interest at any time.

“Taxes” has the meaning set forth in Section 4.4(a).

“Term Loans” means the Closing Date Term Loans and/or the Delayed Draw Term Loans, as the context may require.

“Trust Preferred Obligations” means the subordinated, deferrable interest debt securities of the Borrower, and, without duplication, any related securities issued by a trust or other special purpose entity in connection therewith.

“Unused Fees” has the meaning set forth in Section 3.4(a).

“Unused Delayed Draw Term Loan Commitment” means, for any period from the Closing Date to the Maturity Date, the amount by which (a) the average Delayed Draw Term Loan Commitment for such period exceeds (b) the daily average sum for such period of the aggregate principal amount of all Delayed Draw Term Loans.

“Write-Down and Conversion Powers” means, with respect to any EEA Resolution Authority, the write-down and conversion powers of such EEA Resolution Authority from time to time under the Bail-In Legislation for the applicable EEA Member Country, which write-down and conversion powers are described in the EU Bail-In Legislation Schedule.

1.2Computation of Time Periods and Other Definitional Provisions.

With reference to this Agreement and each other Credit Document, unless otherwise specified herein or in such other Credit Document:

(a)The definitions of terms herein shall apply equally to the singular and plural forms of the terms defined. Whenever the context may require, any pronoun shall include the corresponding masculine, feminine and neuter forms. The words “include,” “includes” and “including” shall be deemed to be followed by the phrase “without limitation.” The word “will” shall be construed to have the same meaning and effect as the word “shall.” Unless the context requires otherwise, (i) any definition of or reference to any agreement, instrument or other document (including any Credit Document) shall be construed as referring to such agreement, instrument or other document as from time to time amended, modified, extended, restated, replaced or supplemented from time to time (subject to any restrictions on such amendments, supplements or modifications set forth herein or in any other Credit Document), (ii) any reference herein to any Person shall be construed to include such Person’s successors and assigns, (iii) the words “hereto,” “herein,” “hereof” and “hereunder,” and words of similar import when used in any Credit Document, shall be construed to refer to such Credit Document in its entirety and not to any particular provision thereof, (iv) all references in a Credit Document to Articles, Sections, Preliminary Statements, Exhibits and Schedules shall be construed to refer to Articles and Sections of, Recitals of and Exhibits and Schedules to, the Credit Document in which such references appear, (v) any reference to any Law shall include all statutory and regulatory rules, regulations, orders and provisions consolidating, amending, replacing or interpreting such Law

14

and any reference to any Law or regulation shall, unless otherwise specified, refer to such Law or regulation as amended, modified, extended, restated, replaced or supplemented from time to time, and (vi) the words “asset” and “property” shall be construed to have the same meaning and effect and to refer to any and all assets and properties, tangible and intangible, real and personal, including cash, securities, accounts and contract rights.

(b)In the computation of periods of time from a specified date to a later specified date, the word “from” means “from and including;” the words “to” and “until” each mean “to but excluding;” and the word “through” means “to and including.”

(c)Section headings herein and in the other Credit Documents are included for convenience of reference only and shall not affect the interpretation of this Agreement or any other Credit Document.

1.3Accounting Terms.

Except as otherwise expressly provided herein, all accounting terms used herein shall be interpreted, and all financial statements and certificates and reports as to financial matters required to be delivered to the Lenders hereunder shall be prepared, in accordance with GAAP applied on a consistent basis. All calculations made for the purposes of determining compliance with this Term Loan Agreement shall (except as otherwise expressly provided herein) be made by application of GAAP applied on a basis consistent with the most recent annual or quarterly financial statements delivered pursuant to Section 7.1 (or, prior to the delivery of the first financial statements pursuant to Section 7.1, consistent with the financial statements described in Section 5.1(e)); provided, however, (a) if (i) the Borrower shall object to determining such compliance on such basis at the time of delivery of such financial statements due to any change in GAAP or the rules promulgated with respect thereto or (ii) the Administrative Agent or the Required Lenders shall so object in writing within 30 days after delivery of such financial statements, then such calculations shall be made on a basis consistent with the most recent financial statements delivered by the Borrower to the Lenders as to which no such objection shall have been made and (b) it is agreed that for purposes of calculations under Section 7.11 of this Agreement, capital lease obligations shall be calculated in accordance with GAAP as of the Closing Date unless otherwise agreed by the Borrower and the Required Lenders.

1.4[Reserved].

1.5Rounding Rates.

Any financial ratios required to be maintained by the Borrower pursuant to this Agreement shall be calculated by dividing the appropriate component by the other component, carrying the result to one place more than the number of places by which such ratio is expressed herein and rounding the result up or down to the nearest number (with a rounding-up if there is no nearest number).The Administrative Agent does not warrant, nor accept responsibility, nor shall the Administrative Agent have any liability with respect to the administration, submission or any other matter related to the rates in the definition of “Eurodollar Base Rate” or with respect to any comparable or successor rate thereto (except such as shall result from the gross negligence or willful misconduct of the Administrative Agent as determined by a final, non-appealable judgment of a court of competent jurisdiction).

SECTION 2.LOANS

15

2.1Term Loans.

(a)Subject to the terms and conditions set forth herein, each Lender severally agrees to make term loans to the Borrower on the Closing Date in Dollars (the “Closing Date Term Loans”); provided, however, that (i) the aggregate amount of Closing Date Term Loans shall not exceed the Closing Date Term Loan Commitments, (ii) with respect to each individual Lender, the Lender’s pro rata share of outstanding Closing Date Term Loans shall not exceed such Lender’s Closing Date Term Loan Commitment Percentage of the Closing Date Term Loan Commitment and (iii) the Closing Date Term Loans shall be Base Rate Loans unless the Borrower delivers a funding indemnity letter in a form satisfactory to the Administrative Agent not less than three (3) Business Days prior to the Closing Date.

(b)Subject to the terms and conditions set forth herein, each Lender severally agrees to make delayed draw term loans to the Borrower in Dollars, (the “Delayed Draw Term Loans”), the proceeds of which shall be drawn in a single drawing on or before October 15, 2016; provided, however, that (x) the aggregate amount of Delayed Draw Term Loans shall not exceed the Delayed Draw Term Loan Commitments and (y) with respect to each individual Lender, the Lender’s pro rata share of outstanding Delayed Draw Term Loans shall not exceed such Lender’s Delayed Draw Term Loan Commitment Percentage of the Delayed Draw Term Loan Commitment.

2.2[Reserved].

2.3[Reserved].

2.4Method of Borrowing for Term Loans.

In the case of Term Loans, by no later than 2:00 p.m. (a) on the date of the requested borrowing of Term Loans that will be Base Rate Loans or (b) three Business Days prior to the date of the requested borrowing of Term Loans that will be Eurodollar Loans, the Borrower shall submit a written Notice of Borrowing of Term Loans in the form of Exhibit 2.4 to the Administrative Agent setting forth (i) the amount requested, (ii) whether such Term Loans shall accrue interest at the Adjusted Base Rate or the Adjusted Eurodollar Rate, (iii) with respect to Term Loans that will be Eurodollar Loans, the Interest Period applicable thereto and (iv) certification that the Borrower has complied in all respects with Section 5.2.

2.5Funding of Term Loans.

Upon receipt of a Notice of Borrowing of Term Loans, the Administrative Agent shall promptly inform the Lenders as to the terms thereof. Each such Lender shall make its Commitment Percentage of the requested Term Loans available to the Administrative Agent by 4:00 p.m. (in the case of any Notice of Borrowing of Term Loans delivered after 12:00 noon) on the date specified in the Notice of Borrowing of Term Loans by deposit in Dollars of immediately available funds at the Administrative Agent’s Office or at such other address as the Administrative Agent may designate in writing, provided, that, for any Notice of Borrowing of Term Loans submitted by the Borrower no later than 12:00 noon, each Lender shall make its Commitment Percentage of the requested Term Loans available to the Administrative Agent by 2:00 p.m. on the date specified in the Notice of Borrowing of Term Loans. The amount of the requested Term Loans will then be made available to the Borrower by the Administrative Agent by crediting the account of the Borrower that is designated on the Notice of Borrowing of Term Loans, to the extent the amount of such Term Loans are made available to the Administrative Agent.

16

No Lender shall be responsible for the failure or delay by any other Lender in its obligation to make Term Loans hereunder; provided,however, that the failure of any Lender to fulfill its obligations hereunder shall not relieve any other Lender of its obligations hereunder. Unless the Administrative Agent shall have been notified by any Lender prior to the time of any such Term Loan that such Lender does not intend to make available to the Administrative Agent its portion of the Term Loans to be made on such date, the Administrative Agent may assume that such Lender has made such amount available to the Administrative Agent on the date of such Term Loans, and the Administrative Agent in reliance upon such assumption, may (in its sole discretion but without any obligation to do so) make available to the Borrower a corresponding amount. If such corresponding amount is not in fact made available to the Administrative Agent, the Administrative Agent shall be able to recover such corresponding amount from such Lender. If such Lender does not pay such corresponding amount forthwith upon the Administrative Agent’s demand therefor, the Administrative Agent will promptly notify the Borrower, and the Borrower shall immediately pay such corresponding amount to the Administrative Agent. The Administrative Agent shall also be entitled to recover from the Lender or the Borrower, as the case may be, interest on such corresponding amount in respect of each day from the date such corresponding amount was made available by the Administrative Agent to the Borrower to the date such corresponding amount is recovered by the Administrative Agent at a per annum rate equal to (i) from the Borrower at the applicable rate for such Term Loan pursuant to the Notice of Borrowing of Term Loans and (ii) from a Lender at the Federal Funds Rate.

2.6Continuations and Conversions.

The Borrower shall have the option, on any Business Day, to continue existing Eurodollar Loans for a subsequent Interest Period, to convert Base Rate Loans into Eurodollar Loans or to convert Eurodollar Loans in Dollars into Base Rate Loans; provided, however, that (a) each such continuation or conversion must be requested by the Borrower pursuant to a written Notice of Continuation/Conversion, in the form of Exhibit 2.6, in compliance with the terms set forth below, (b) except as provided in Section 4.1, Eurodollar Loans may only be continued or converted into Base Rate Loans on the last day of the Interest Period applicable hereto, (c) Eurodollar Loans may not be continued nor may Base Rate Loans be converted into Eurodollar Loans during the existence and continuation of a Default or Event of Default and (d) any request to extend a Eurodollar Loan that fails to comply with the terms hereof or any failure to request an extension of a Eurodollar Loan at the end of an Interest Period shall constitute a conversion in each case, to a Base Rate Loan on the last day of the applicable Interest Period. Each continuation or conversion must be requested by the Borrower no later than 12:00 p.m. (noon) (i) on the date for a requested conversion of a Eurodollar Loan to a Base Rate Loan or (ii) three Business Days prior to the date for a requested continuation of a Eurodollar Loan or conversion of a Base Rate Loan to a Eurodollar Loan, in each case pursuant to a written Notice of Continuation/Conversion submitted to the Administrative Agent which shall set forth (A) whether the Borrower wishes to continue or convert such Loans and (B) if the request is to continue a Eurodollar Loan or convert a Base Rate Loan to a Eurodollar Loan, the Interest Period applicable thereto.

2.7Minimum Amounts. Each request for a conversion or continuation hereunder shall be subject to the following requirements: (a) each Eurodollar Loan shall be in a minimum of $5,000,000, (b) each Base Rate Loan shall be in a minimum amount of the lesser of $5,000,000 or the remaining amount available to be borrowed and (c) no more than five Eurodollar Loans shall be outstanding hereunder at any one time. For the purposes of this Section 2.7, all Eurodollar Loans with the same Interest Periods shall be considered as one Eurodollar Loan, but Eurodollar Loans with different Interest Periods, even if they begin on the same date, shall be considered separate Eurodollar Loans.

2.8Reductions of Term Loan Commitment.

17

Upon at least three Business Days’ prior written notice to the Administrative Agent (which notice shall be promptly transmitted by the Administrative Agent to each Lender), the Borrower shall have the right to permanently terminate or reduce the aggregate unused amount of the Delayed Draw Term Loan Commitment, at any time or from time to time; provided that (a) each partial reduction shall be in an aggregate amount at least equal to $10,000,000 and in integral multiples of $1,000,000 above such amount, and (b) no reduction shall be made which would reduce the Delayed Draw Term Loan Commitment to an amount less than the then outstanding Delayed Draw Term Loans. Any reduction in (or termination of) the Delayed Draw Term Loan Facility shall be permanent and may not be reinstated.

2.9Evidence of Obligations.

(a)Lender Records. The date, amount, type, interest rate and duration of Interest Period (if applicable) of each Loan made by each Lender to the Borrower, and each payment made on account of the principal thereof, shall be recorded by such Lender on its books; provided that the failure of such Lender to make any such recordation or endorsement shall not affect the obligations of the Borrower to make a payment when due of any amount owing hereunder or under any Note in respect of the Term Loans to be evidenced by such Note, and each such recordation or endorsement shall be conclusive and binding absent manifest error.

(b)Notes. (i) The Closing Date Term Loans made by the Lenders shall be evidenced by a promissory note of the Borrower payable to each Lender (to the extent requested by such Lender) in substantially the form of Exhibit 2.9(a) (the “Closing Date Term Loan Notes”) and (ii) the Delayed Draw Term Loans made by the Lenders shall be evidenced by a promissory note of the Borrower payable to each Lender (to the extent requested by such Lender) in substantially the form of Exhibit 2.9(b) (the “Delayed Draw Term Loan Notes”)and shall be delivered by the Borrower to such Lender with reasonable promptness upon such request.

2.10[Reserved].

2.11[Reserved].

2.12[Reserved].

2.13Defaulting Lenders.

(a)Defaulting Lender Adjustments. Notwithstanding anything to the contrary contained in this Agreement, if any Lender becomes a Defaulting Lender, then, until such time as that Lender is no longer a Defaulting Lender, to the extent permitted by applicable Law:

(i)Waivers and Amendments. That Defaulting Lender’s right to approve or disapprove any amendment, waiver or consent with respect to this Term Loan Agreement shall be restricted as set forth in Section 11.6.

(ii)Defaulting Lender Waterfall. Any payment of principal, interest, fees or other amounts received by the Administrative Agent for the account of that Defaulting Lender under this Term Loan Agreement (whether voluntary or mandatory, at maturity, pursuant to Article IX or otherwise) or received by the Administrative Agent from a Defaulting Lender pursuant to Section 11.2, shall be applied at such time or times as may be determined by the Administrative Agent as follows: first, to the payment of any amounts owing by that Defaulting Lender to the Administrative Agent hereunder; second, as the Borrower may request (so long as no Default exists), to the funding of any Loan in

18

respect of which such Defaulting Lender has failed to fund its portion thereof as required by this Agreement, as determined by the Administrative Agent; third, if so determined by the Administrative Agent and the Borrower, to be held in a deposit account and released pro rata in order to satisfy such Defaulting Lender’s potential future funding obligations with respect to Loans under this Agreement; fourth, to the payment of any amounts owing to the Lenders as a result of any judgment of a court of competent jurisdiction obtained by any Lender against such Defaulting Lender as a result of such Defaulting Lender’s breach of its obligations under this Agreement; fifth, so long as no Default or Event of Default exists, to the payment of any amounts owing to the Borrower as a result of any judgment of a court of competent jurisdiction obtained by the Borrower against such Defaulting Lender as a result of such Defaulting Lender’s breach of its obligations under this Agreement; and sixth, to that Defaulting Lender or as otherwise directed by a court of competent jurisdiction; provided that if (x) such payment is a payment of the principal amount of any Loans in respect of which that Defaulting Lender has not fully funded its appropriate share and (y) such Loans were made at a time when the conditions set forth in Section 5.2 were satisfied or waived, such payment shall be applied solely to pay the Loans of all Non-Defaulting Lenders on a pro rata basis prior to being applied to the payment of any Loans of such Defaulting Lender until such time as all Loans are held by the Lenders pro rata in accordance with the Commitments. Any payments, prepayments or other amounts paid or payable to a Defaulting Lender that are applied (or held) to pay amounts owed by a Defaulting Lender pursuant to this Section 2.13(a)(ii) shall be deemed paid to and redirected by that Defaulting Lender, and each Lender irrevocably consents hereto.

(iii)Fees. A Defaulting Lender shall not be entitled to receive any fees accrued hereunder while it is a Defaulting Lender.

(b)Defaulting Lender Cure. If the Borrower and the Administrative Agent agree in writing that a Lender is no longer a Defaulting Lender, the Administrative Agent will so notify the parties hereto, whereupon as of the effective date specified in such notice and subject to any conditions set forth therein, that Lender will, to the extent applicable, purchase at par that portion of outstanding Loans of the other Lenders or take such other actions as the Administrative Agent may determine to be necessary to cause the Loans to be held on a pro rata basis by the Lenders in accordance with their Commitment Percentages, whereupon that Lender will cease to be a Defaulting Lender; provided that no adjustments will be made retroactively with respect to fees accrued or payments made by or on behalf of the Borrower while that Lender was a Defaulting Lender; and provided, further, that except to the extent otherwise expressly agreed by the affected parties, subject to Section 11.20, no change hereunder from Defaulting Lender to Lender will constitute a waiver or release of any claim of any party hereunder arising from that Lender’s having been a Defaulting Lender.

SECTION 3.PAYMENTS

3.1Interest.

(a)Interest Rate.

(i)All Base Rate Loans shall accrue interest at the Adjusted Base Rate.

19

(ii)All Eurodollar Loans shall accrue interest at the Adjusted Eurodollar Rate applicable to such Eurodollar Loan.

(b)Default Rate of Interest. Upon the occurrence, and during the continuance, of an Event of Default, the principal of and, to the extent permitted by law, interest on the Loans and any other amounts owing hereunder or under the other Credit Documents shall bear interest, payable on demand, at the Default Rate.

(c)Interest Payments. Interest on Loans shall be due and payable in arrears on each Interest Payment Date.

3.2Voluntary Prepayments.

The Borrower shall have the right to prepay Loans in whole or in part from time to time without premium or penalty; provided, however, that (i) Eurodollar Loans may only be prepaid on three Business Days’ prior written notice to the Administrative Agent and any prepayment of Eurodollar Loans will be subject to Section 4.3; and (ii) each such partial prepayment of Loans shall be in the minimum principal amount of $5,000,000. Amounts prepaid hereunder shall be applied as the Borrower may elect; provided that if the Borrower fails to specify the application of a voluntary prepayment then such prepayment shall be applied first to Term Loans that are Base Rate Loans, and second to Eurodollar Loans in direct order of Interest Period maturities.

3.3Payment in Full at Maturity.

On the Maturity Date, the entire outstanding principal amount owing under the Credit Documents, together with accrued but unpaid interest and all other sums owing under the Credit Documents shall be due and payable in full, unless accelerated sooner pursuant to Section 9.2.

3.4Fees.

(a)Unused Fees.

(i)In consideration of the Delayed Draw Term Loans being made available by the Lenders hereunder, the Borrower agrees to pay to the Administrative Agent, for the pro rata benefit of each Lender, a per annum fee equal to the Applicable Percentage for Unused Fees multiplied by the Unused Delayed Draw Term Loan Commitment (the “Unused Fees”).

(ii)The accrued Unused Fees shall be due and payable in arrears fifteen days after the end of each fiscal quarter of the Borrower for the immediately preceding fiscal quarter (or portion thereof), beginning with the first of such dates to occur after the Closing Date, as well as on the Maturity Date.

(b)Administrative Fees. The Borrower agrees to pay to the Administrative Agent, for its own account, the administrative fee as agreed to between the Borrower and the Administrative Agent in the Fee Letter among the Borrower, Bank of America, N.A. and MLPF&S.

3.5Place and Manner of Payments.

20

All payments of principal, interest, fees, expenses and other amounts to be made by the Borrower under this Term Loan Agreement shall be made unconditionally and without deduction for any counterclaim, defense, recoupment or setoff. All such payments shall be received not later than 2:00 p.m. on the date when due in Dollars and in immediately available funds by the Administrative Agent at the Administrative Agent’s Office, or any other designated location specified by the Administrative Agent. The Administrative Agent will distribute such payments made to the Lenders on the date of receipt if such payment is received prior to 2:00 p.m.; otherwise, the Administrative Agent will distribute such payments to the Lenders, and such payment will be credited to the Borrower, on the next succeeding Business Day. The Borrower shall, at the time it makes any payment under this Term Loan Agreement, specify to the Administrative Agent the Loans, fees or other amounts payable by the Borrower hereunder to which such payment is to be applied (and in the event that it fails to specify, or if such application would be inconsistent with the terms hereof, the Administrative Agent shall distribute such payment to the Lenders in such manner as it reasonably determines in its sole discretion). Whenever any payment hereunder shall be stated to be due on a day which is not a Business Day, the due date thereof shall be extended to the next succeeding Business Day (subject to accrual of interest and fees for the period of such extension), except that, in the case of Eurodollar Loans (or interest payable with respect thereto), if the extension would cause the payment to be made in the next following calendar month, then such payment shall instead be made on the next preceding Business Day.

3.6Pro Rata Treatment.

Except to the extent otherwise provided herein, all Term Loans, each payment or prepayment of principal of any Term Loan, each payment of interest on the Term Loans, each payment of Unused Fees, each reduction of the Delayed Draw Term Loan Commitment, and each conversion or continuation of any Term Loans, shall be allocated pro rata among the Lenders in accordance with the respective Commitment Percentages; provided that, if any Lender shall have failed to pay its applicable pro rata share of any Term Loan and such amount was made available to the Borrower pursuant to Section 2.5, then any amount to which such Lender would otherwise be entitled pursuant to this Section 3.6 shall instead be payable to the Administrative Agent until the share of such Term Loan not funded by such Lender has been repaid; providedfurther that, in the event that any amount paid to any Lender pursuant to this Section 3.6 is rescinded or must otherwise be returned by the Administrative Agent, each Lender shall, upon the request of the Administrative Agent, repay to the Administrative Agent the amount so paid to such Lender, with interest for the period commencing on the date such payment is returned by the Administrative Agent until the date the Administrative Agent receives such payment at a rate per annum equal to the Federal Funds Rate.

3.7Computations of Interest and Fees.

(a)Except for Base Rate Loans bearing interest based on the Prime Rate, on which interest shall be computed on the basis of a 365 or 366 day year, as the case may be, all computations of interest and fees hereunder shall be made on the basis of the actual number of days elapsed over a year of 360 days.

(b)It is the intent of the Lenders and the Borrower to conform to and contract in strict compliance with applicable usury Law from time to time in effect. All agreements between the Lenders and the Borrower are hereby limited by the provisions of this paragraph which shall override and control all such agreements, whether now existing or hereafter arising and whether written or oral. In no way, nor in any event or contingency (including but not limited to prepayment or acceleration of the maturity of any obligation), shall the interest taken, reserved, contracted for, charged, or received under this Term Loan Agreement, under any Notes or otherwise, exceed the maximum nonusurious amount permissible under applicable Law. If, from

21

any possible construction of any of the Credit Documents or any other document, interest would otherwise be payable in excess of the maximum nonusurious amount, any such construction shall be subject to the provisions of this paragraph and such documents shall be automatically reduced to the maximum nonusurious amount permitted under applicable Law, without the necessity of execution of any amendment or new document. If any Lender shall ever receive anything of value which is characterized as interest on the Loans under applicable Law and which would, apart from this provision, be in excess of the maximum lawful amount, an amount equal to the amount which would have been excessive interest shall, without penalty, be applied to the reduction of the principal amount owing on the Loans and not to the payment of interest, or refunded to the Borrower or the other payor thereof if and to the extent such amount which would have been excessive exceeds such unpaid principal amount of the Loans. The right to demand payment of the Loans or any other indebtedness evidenced by any of the Credit Documents does not include the right to receive any interest which has not otherwise accrued on the date of such demand, and the Lenders do not intend to charge or receive any unearned interest in the event of such demand. All interest paid or agreed to be paid to the Lenders with respect to the Loans shall, to the extent permitted by applicable Law, be amortized, prorated, allocated, and spread throughout the full stated term (including any renewal or extension) of the Loans so that the amount of interest on account of such indebtedness does not exceed the maximum nonusurious amount permitted by applicable Law.

3.8Sharing of Payments.

Each Lender agrees that, in the event that any Lender shall obtain payment in respect of any Loan or other Borrower Obligation owing to such Lender under this Term Loan Agreement through the exercise of a right of set-off, banker’s lien, counterclaim or otherwise (including, but not limited to, pursuant to the Bankruptcy Code) in excess of its pro rata share as provided for in this Term Loan Agreement, such Lender shall promptly purchase from the other Lenders a participation in such Loans or Borrower Obligations, in such amounts and with such other adjustments from time to time, as shall be equitable in order that all Lenders share such payment in accordance with their respective ratable shares as provided for in this Term Loan Agreement. Each Lender further agrees that if a payment to a Lender (which is obtained by such Lender through the exercise of a right of set-off, banker’s lien, counterclaim or otherwise) shall be rescinded or must otherwise be restored, each Lender which shall have shared the benefit of such payment shall, by repurchase of a participation theretofore sold, return its share of that benefit to each Lender whose payment shall have been rescinded or otherwise restored, together with its pro rata share of any interest required to be paid by the Lender whose payment shall have been rescinded or otherwise restored. The Borrower agrees that any Lender so purchasing such a participation may, to the fullest extent permitted by law, exercise all rights of payment, including set-off, banker’s lien or counterclaim, with respect to such participation as fully as if such Lender were a holder of such Loan or other obligation in the amount of such participation. Except as otherwise expressly provided in this Term Loan Agreement, if any Lender shall fail to remit to the Administrative Agent or any other Lender an amount payable by such Lender to the Administrative Agent or such other Lender pursuant to this Term Loan Agreement on the date when such amount is due, such payments shall accrue interest thereon, for each day from the date such amount is due until the day such amount is paid to the Administrative Agent or such other Lender, at a rate per annum equal to the Federal Funds Rate. The provisions of this Section shall not be construed to apply to any payment made by or on behalf of the Borrower pursuant to and in accordance with Section 2.13 of this Agreement (including the application of funds arising from the existence of a Defaulting Lender).

22

SECTION 4.

ADDITIONAL PROVISIONS REGARDING LOANS

4.1Eurodollar Loans.

(a)Unavailability. In the event that the Administrative Agent shall have determined in good faith (i) that Dollar deposits in the principal amounts requested with respect to a Eurodollar Loan are not generally available in the London interbank Eurodollar market or (ii) that reasonable means do not exist for ascertaining the Eurodollar Rate or the Required Lenders shall have notified the Administrative Agent that the Eurodollar Rate for any requested Interest Period with respect to a proposed Eurodollar Loan does not adequately and fairly reflect the cost to such Lenders of funding such Loan, the Administrative Agent shall, as soon as practicable thereafter, give written notice of such determination to the Borrower and the Lenders. In the event of any such determination under clauses (i) or (ii) above, until the Administrative Agent shall have advised the Borrower and the Lenders that the circumstances giving rise to such notice no longer exist, (A) any request by the Borrower for Eurodollar Loans shall be deemed to be a request for Base Rate Loans and (B) any request by the Borrower for conversion into or continuation of Eurodollar Loans shall be deemed to be a request for conversion into or continuation of Base Rate Loans.

(b)Change in Legality.

Notwithstanding any other provision herein, if any (i) adoption or taking effect of any Law, (ii) any change in any Law or in the administration, interpretation, implementation or application thereof by any Governmental Authority or (iii) the making or issuance of any request, rule, guideline or directive (whether or not having the force of Law) by any Governmental Authority (provided, that notwithstanding anything herein to the contrary, (x) the Dodd-Frank Wall Street Reform and Consumer Protection Act and all requests, rules, guidelines or directives thereunder or issued in connection therewith and (y) all requests, rules, guidelines or directives promulgated by the Bank for International Settlements, the Basel Committee on Banking Supervision (or any successor or similar authority) or the United States or foreign regulatory authorities, in each case pursuant to Basel III, shall in each case be deemed to be a change in law for purposes hereof, regardless of the date enacted, adopted, implemented or issued) shall make it unlawful for any Lender to make or maintain any Eurodollar Loan or to give effect to its obligations as contemplated hereby with respect to any Eurodollar Loan, then, by written notice to the Borrower and to the Administrative Agent, such Lender may, until such time as the circumstances giving rise to such unlawfulness no longer exists:

(A)declare that Eurodollar Loans, and conversions to or continuations of Eurodollar Loans, will not thereafter be made by such Lender hereunder, whereupon any request by the Borrower for, or for conversion into or continuation of, Eurodollar Loans shall, as to such Lender only, be deemed a request for, or for conversion into or continuation of, Base Rate Loans, unless such declaration shall be subsequently withdrawn; and

(B)require that all outstanding Eurodollar Loans made by it be converted to Base Rate Loans in which event all such Eurodollar Loans shall be automatically converted to Base Rate Loans.

23

In the event any Lender shall exercise its rights under clause (A) or (B) above, all payments and prepayments of principal which would otherwise have been applied to repay the Eurodollar Loans that would have been made by such Lender or the converted Eurodollar Loans of such Lender shall instead be applied to repay the Base Rate Loans made by such Lender in lieu of, or resulting from the conversion of, such Eurodollar Loans.

(c)Increased Costs. If at any time a Lender shall incur increased costs or reductions in the amounts received or receivable hereunder with respect to the making, the commitment to make or the maintaining of any Eurodollar Loan because of (i) any adoption or taking effect of any Law, (ii) any change in any Law or in the administration, interpretation, implementation or application thereof by any Governmental Authority or (iii) the making or issuance of any request, rule, guideline or directive (whether or not having the force of Law) by any Governmental Authority including, without limitation, the imposition, modification or deemed applicability of any reserves, deposits or similar requirements (such as, for example, but not limited to, a change in official reserve requirements, but, in all events, excluding reserves required under Regulation D to the extent included in the computation of the Adjusted Eurodollar Rate) (provided, that notwithstanding anything herein to the contrary, (x) the Dodd-Frank Wall Street Reform and Consumer Protection Act and all requests, rules, guidelines or directives thereunder or issued in connection therewith and (y) all requests, rules, guidelines or directives promulgated by the Bank for International Settlements, the Basel Committee on Banking Supervision (or any successor or similar authority) or the United States or foreign regulatory authorities, in each case pursuant to Basel III, shall in each case be deemed to be a change in law for purposes hereof, regardless of the date enacted, adopted or issued), then the Borrower shall pay to such Lender within 15 days after demand, which demand shall contain the basis and calculations supporting such demand, such additional amounts (in the form of an increased rate of, or a different method of calculating, interest or otherwise as such Lender may determine in its sole discretion) as may be required to compensate such Lender for such increased costs or reductions in amounts receivable hereunder.

Each determination and calculation made by a Lender under this Section 4.1 shall, absent manifest error, be binding and conclusive on the parties hereto.

4.2Capital Adequacy.

If, after the date hereof, any Lender has determined that the adoption or effectiveness of any applicable Law, rule or regulation regarding capital adequacy or liquidity, or any change therein, or any change in the interpretation or administration thereof by any Governmental Authority, central bank or comparable agency charged with the interpretation or administration thereof, or compliance by such Lender with any request or directive regarding capital adequacy or liquidity (whether or not having the force of law) of any such authority, central bank or comparable agency, has or would have the effect of reducing the rate of return on such Lender’s (or parent corporation’s) capital or assets as a consequence of its commitments or obligations hereunder to a level below that which such Lender, or its parent corporation, could have achieved but for such adoption, effectiveness, change or compliance (taking into consideration such Lender’s (or parent corporation’s) policies with respect to capital adequacy and liquidity)(provided, that notwithstanding anything herein to the contrary, (x) the Dodd-Frank Wall Street Reform and Consumer Protection Act and all requests, rules, guidelines or directives thereunder or issued in connection therewith and (y) all requests, rules, guidelines or directives promulgated by the Bank for International Settlements, the Basel Committee on Banking Supervision (or any successor or similar authority) or the United States or foreign regulatory authorities, in each case pursuant to Basel III, shall in each case be deemed to be a change in law for purposes hereof, regardless of the date enacted, adopted, implemented or issued), then the Borrower shall pay to such Lender within 15 days after demand, which demand shall contain the basis and calculations supporting such demand, such additional amount or

24

amounts as will compensate such Lender for such reduction. Each determination by any such Lender of amounts owing under this Section 4.2 shall, absent manifest error, be conclusive and binding on the parties hereto.

4.3Compensation.

The Borrower shall compensate each Lender, within 15 days after demand, which demand shall contain the basis and calculations supporting such demand, for all reasonable losses, expenses and liabilities (including, without limitation, any loss, expense or liability incurred by reason of the liquidation or reemployment of deposits or other funds required by the Lender to fund its Eurodollar Loans) which such Lender may sustain:

(a)if for any reason (other than a default by such Lender or the Administrative Agent) a borrowing, continuation or conversion of Eurodollar Loans does not occur on a date specified therefor in a Notice of Borrowing of Term Loans or Notice of Continuation/Conversion, as the case may be;

(b)if any prepayment, repayment, continuation or conversion of any Eurodollar Loan occurs on a date which is not the last day of an Interest Period applicable thereto, including, without limitation, in connection with any demand, acceleration, mandatory prepayment or otherwise (including any demand under this Section 4);

(c)if the Borrower fails to repay its Eurodollar Loans when required by the terms of this Term Loan Agreement; or

(d)if the Borrower elects to cause a mandatory assignment of such Lender’s Commitment pursuant to Section 4.5.

Calculation of all amounts payable to a Lender under this Section 4.3 shall be made as though the Lender has actually funded its relevant Eurodollar Loan through the purchase of a Eurodollar deposit bearing interest at the Adjusted Eurodollar Rate in an amount equal to the amount of that Loan, having a maturity comparable to the relevant Interest Period and through the transfer of such Eurodollar deposit from an offshore office of that Lender to a domestic office of that Lender in the United States of America; provided, however, that each Lender may fund each of its Eurodollar Loans in any manner it sees fit and the foregoing assumption shall be utilized only for the calculation of amounts payable under this Section 4.3. Each determination and calculation hereunder shall be in good faith and shall be conclusive absent manifest error.

4.4Taxes.

(a)Tax Liabilities Imposed on a Lender. (i) Any and all payments by the Borrower hereunder or under any of the Credit Documents shall be made, in accordance with the terms hereof and thereof, free and clear of and without deduction for any and all present or future taxes, levies, imposts, deductions, charges or withholdings, and all liabilities with respect thereto, excluding (A) taxes measured by net income and franchise taxes imposed on any Lender by the jurisdiction under the laws of which such Lender is organized or transacting business or any political subdivision thereof and (B) any U.S. federal withholding taxes imposed under FATCA (all such non‑excluded taxes, being hereinafter referred to as “Taxes”). If any applicable Laws (as determined in the good faith discretion of the Administrative Agent or Borrower, as applicable) require the deduction or withholding of any tax from any such payment hereunder,

25

then the Administrative Agent or Borrower shall be entitled to make such deduction or withholding.

(ii)Without limiting the rights of the Borrower in clause (i) above, if the Borrower or the Administrative Agent shall be required by the Code to deduct any taxes from or in respect of any sum payable hereunder to any Lender, (A) to the extent that the withholding or deduction is made on account Taxes, the sum payable by the Borrower shall be increased as may be necessary so that after making all required deductions (including deductions applicable to additional sums payable under this Section 4.4) such Lender or the Administrative Agent receives an amount equal to the sum it would have received had no such deductions been made, (B) the Administrative Agent shall make such deductions and (C) the Administrative Agent shall pay the full amount deducted to the relevant Governmental Authority in accordance with the Code.

(iii)If the Borrower or the Administrative Agent shall be required by applicable Law other than the Code to deduct any taxes from or in respect of any sum payable hereunder to any Lender, (A) to the extent that the withholding or deduction is made on account Taxes, the sum payable by the Borrower shall be increased as may be necessary so that after making all required deductons (including deductions applicable to additional sums payable under this Section 4.4) such Lender or the Administrative Agent receives an amount equal to the sum it would have received had no such deductions been made, (B) the Borrower or Administrative Agent, as required by such law, shall pay the full amount deducted to the relevant Governmental Authority in accordance with applicable Law.

(b)Other Taxes. In addition, the Borrower agrees to pay, upon written notice from a Lender and prior to the date when penalties attach thereto, all present or future stamp or documentary taxes or any other excise or property taxes, charges or similar levies of the United States or any state or political subdivision thereof or any applicable foreign jurisdiction that arise from any payment made hereunder or from the execution, delivery or registration of, or otherwise with respect to, this Term Loan Agreement (collectively, the “Other Taxes”).

(c)Refunds. If a Lender or the Administrative Agent (as the case may be) shall become aware that it is entitled to claim a refund (or a refund in the form of a credit) (each, a “Refund”) from a Governmental Authority (as a result of any error in the amount of Taxes or Other Taxes paid to such Governmental Authority or otherwise) of Taxes or Other Taxes which the Borrower has paid, or with respect to which the Borrower has paid additional amounts, pursuant to this Section 4.4, it shall promptly notify the Borrower in writing of the availability of such Refund and shall, within 30 days after receipt of written notice by the Borrower make a claim to such Governmental Authority for such Refund at the Borrower’s expense if, in the judgment of such Lender or the Administrative Agent (as the case may be), the making of such claim will not be otherwise disadvantageous to it; provided that nothing in this subsection (c) shall be construed to require any Lender or the Administrative Agent to institute any administrative proceeding (other than the filing of a claim for any such Refund) or judicial proceeding to obtain such Refund.

If a Lender or the Administrative Agent (as the case may be) receives a Refund from a Governmental Authority (as a result of any error in the amount of Taxes or Other Taxes paid to such Governmental Authority or otherwise) of any Taxes or Other Taxes which have been paid by the Borrower, or with respect to which the Borrower has paid additional amounts pursuant to this Section 4.4, it shall promptly pay to the Borrower the amount so received (but only to the

26

extent of payments made, or additional amounts paid, by the Borrower under this Section 4.4 with respect to Taxes or Other Taxes giving rise to such Refund), net of all reasonable out‑of‑pocket expenses (including the net amount of taxes, if any, imposed on such Lender or the Administrative Agent with respect to such Refund) of such Lender or Administrative Agent, and without interest (other than interest paid by the relevant Governmental Authority with respect to such Refund); provided, however, that the Borrower, upon the request of such Lender or the Administrative Agent, agrees to repay the amount paid over to the Borrower (plus penalties, interest or other charges) to such Lender or the Administrative Agent in the event such Lender or the Administrative Agent is required to repay such Refund to such Governmental Authority. Nothing contained in this Section 4.4(c) shall require any Lender or the Administrative Agent to make available any of its tax returns (or any other information that it deems to be confidential or proprietary) or to alter its tax accounting practices.

(d)Foreign Lender. Each Lender (which, for purposes of this Section 4.4, shall include any Affiliate of a Lender that makes any Eurodollar Loan pursuant to the terms of this Term Loan Agreement) that is not a “United States person” (as such term is defined in Section 7701(a)(30) of the Code) shall submit to the Borrower and the Administrative Agent on or before the Closing Date (or, in the case of a Person that becomes a Lender after the Closing Date by assignment, promptly upon such assignment), two duly completed and signed copies of (1) Form W-8BEN or W-8BEN-E, as applicable, of the United States Internal Revenue Service, or a successor applicable form, entitling such Lender to a complete exemption from withholding on all amounts to be received by such Lender pursuant to this Term Loan Agreement and/or any Notes, (2) Form W-8ECI of the United States Internal Revenue Service, or a successor applicable form, relating to all amounts to be received by such Lender pursuant to this Term Loan Agreement and/or any Notes or (3) any other form (together with supplementary documentation) prescribed by applicable Laws entitling such Lender to a complete exemption from United States withholding tax. Each such Lender shall, from time to time after submitting either such form, submit to the Borrower and the Administrative Agent such additional duly completed and signed copies of such forms (or such successor forms or other documents as shall be adopted from time to time by the relevant United States taxing authorities) as may be (1) reasonably requested in writing by the Borrower or the Administrative Agent and (2) appropriate under then current United States laws or regulations. If and for any period during which the provisions of this Section 4.4(d) are not satisfied by or with respect to any such Lender, no provision of this Term Loan Agreement shall require the Borrower to indemnify with respect to any resulting withholding of United States taxes imposed on or with respect to such Lender as a result of such noncompliance for the periods to which such noncompliance relates, unless such noncompliance is directly attributable to a change in a law, rule or regulation issued by a Governmental Authority which results in the inability of such Lender to provide such form. If a payment made to a Lender hereunder would be subject to United States federal withholding tax imposed by FATCA if such Lender were to fail to comply with the applicable requirements of FATCA, such Lender shall deliver to the Borrower and the Administrative Agent, at the time or times prescribed by Law and at such time or times reasonably requested by the Borrower or the Administrative Agent, such documentation prescribed by applicable Law and such additional documentation reasonably requested by the Borrower or the Administrative Agent as may be necessary for the Borrower and the Administrative Agent to comply with its obligations under FATCA, to determine that such Lender has or has not complied with such Lender’s obligations under FATCA or to determine the amount to deduct and withhold from such payment.

(e)United States Lenders. Each Lender that is a United States Person shall, on or prior to the date it becomes a party hereto and from time to time thereafter if requested in writing by the Borrower or the Administrative Agent, provide the Administrative Agent and the Borrower

27

with a properly completed and duly executed copy of Internal Revenue Service Form W-9, or any successor to such form.

4.5Mitigation; Mandatory Assignment.

The Administrative Agent and each Lender shall use reasonable efforts to avoid or mitigate any increased cost or suspension of the availability of an interest rate or the payment of Taxes or Other Taxes under Sections 4.1 through 4.4 above to the greatest extent practicable (including transferring the Loans to another lending office or Affiliate of a Lender) unless, in the reasonable opinion of the Administrative Agent or such Lender, such efforts would be likely to have an adverse effect upon it. In the event (a) a Lender makes a request to the Borrower for additional payments in accordance with Section 4.1, 4.2 or 4.4, (b) a Lender is a Defaulting Lender or (c) a Lender does not consent to a proposed amendment, change, waiver, discharge or termination with respect to any Credit Document to which the Required Lenders have consented (a “Non-Consenting Lender”), then, provided that no Default or Event of Default has occurred and is continuing at such time, the Borrower may, at its own expense (such expense to include any transfer fee payable to the Administrative Agent under Section 11.3(b) and any expense pursuant to Section 4) and in its sole discretion, require any such Lender to transfer and assign in whole (but not in part), without recourse (in accordance with and subject to the terms and conditions of Section 11.3(b)), all of its interests, rights and obligations under this Term Loan Agreement to an Eligible Assignee which shall assume such assigned obligations (which assignee may be another Lender, if a Lender accepts such assignment); provided that (a) such assignment shall not conflict with any law, rule or regulation or order of any court or other Governmental Authority, (b) the Borrower or such assignee shall have paid to the assigning Lender in immediately available funds the principal of and interest accrued to the date of such payment on the portion of the Loans hereunder held by such assigning Lender and all other amounts owed to such assigning Lender hereunder, including amounts owed pursuant to Sections 4.1 through 4.4 and (c) in the case of any such assignment resulting from a Non-Consenting Lender’s failure to consent to a proposed change, waiver, discharge or termination with respect to any Credit Document, the applicable replacement bank, financial institution or Fund consents to the proposed amendment, change, waiver, discharge or termination. In the event any assigning Lender fails to promptly execute the agreements required under Section 11.3(b) in connection with an assignment pursuant to this Section 4.5, the Borrower may, upon one (1) Business Day’s prior notice to such assigning Lender, execute such agreements on behalf of such assigning Lender.

SECTION 5.CONDITIONS PRECEDENT

5.1Closing Conditions.

The obligation of each Lender to enter into this Term Loan Agreement is subject to satisfaction of the following conditions on or prior to the Closing Date (in form and substance acceptable to the Lenders):

(a)Executed Credit Documents. Receipt by the Administrative Agent of duly executed copies of (i) this Term Loan Agreement and (ii) the Notes (to the extent requested by the Lenders).

(b)Officer’s Certificate. Receipt by the Administrative Agent of a certificate of a Responsible Officer of the Borrower stating that, as of the Closing Date, (i) there exists no Default or Event of Default, (ii) all representations and warranties contained herein and in the other Credit Documents are true and correct in all material respects, (iii) the Borrower is in

28

compliance with the financial covenant set forth in Section 7.11, as demonstrated by the covenant calculations on a schedule attached thereto and (iv) the conditions set forth in Sections 5.1(g) and (i) have been satisfied.

(c)Opinion of Counsel. Receipt by the Administrative Agent of an opinion, or opinions, satisfactory to the Administrative Agent, addressed to the Administrative Agent and each of the Lenders from legal counsel to the Borrower.

(d)Corporate Documents. Receipt by the Administrative Agent of the following:

(i)Charter Documents. A certificate of a secretary or assistant secretary of the Borrower certifying that no amendment to the Articles of Incorporation of the Borrower filed on July 12, 1972, or the Certificate of Incorporation issued by the Secretary of State of the State of Mississippi, has been filed since April 2, 2004.

(ii)Bylaws. A copy of the bylaws of the Borrower certified by a secretary or assistant secretary of the Borrower to be true and correct as of the Closing Date.

(iii)Resolutions. Copies of resolutions of the Board of Directors of the Borrower approving and adopting the Credit Documents to which it is a party and the transactions contemplated therein and authorizing execution and delivery thereof, certified by a secretary or assistant secretary of the Borrower to be true and correct and in force and effect as of the Closing Date.

(iv)Good Standing. Copies of (A) certificates of good standing, existence or its equivalent with respect to the Borrower certified as of a recent date by the appropriate Governmental Authorities of the state or other jurisdiction of incorporation and the principal place of business of the Borrower and (B) to the extent available, a certificate indicating payment of all corporate franchise taxes certified as of a recent date by the appropriate Governmental Authorities of the state or other jurisdiction of its incorporation and the principal place of business of the Borrower.

(v)Incumbency. An incumbency certificate of the Borrower, certified by a secretary or assistant secretary of the Borrower to be true and correct as of the Closing Date.

(e)Financial Statements. Receipt by the Lenders of the consolidated audited financial statements of the Borrower dated as of December 31, 2015, including balance sheets and income and cash flow statements, in each case audited by independent public accountants of recognized standing and prepared in accordance with GAAP.

(f)Fees and Expenses. Payment by the Borrower of all fees and expenses owed by it to the Lenders, the Arrangers and the Administrative Agent, including, without limitation, payment of the fees agreed to by the Borrower in the Fee Letters.

(g)Material Adverse Effect. No event or condition shall have occurred since the date of the financial statements delivered pursuant to Section 5.1(e) above that has had or would be likely to have a Material Adverse Effect.

(h)Termination of Existing Term Loan Agreements. Receipt by the Lender of evidence that all obligations under the Existing Term Loan Agreements have been, or

29

substantially simultaneously with the Closing Date will be, paid in full and all commitments thereunder terminated.

(i)Litigation. Except as disclosed in the Borrower’s annual report on Form 10‑K for the year ended December 31, 2015 and in any current report on Form 8-K filed by the Borrower between December 31, 2015 and the Closing Date, there shall not exist any action, suit, investigation or proceeding, nor shall any action, suit or investigation be pending or, to the knowledge of the Borrower, threatened in any court or before any arbitrator or Governmental Authority that materially adversely affects the Borrower or any transaction contemplated hereby or the ability of the Borrower to perform its obligations under the Credit Documents.

(j)Other. Receipt by the Lenders of such other documents, instruments, agreements or information as reasonably requested by any Lender.

5.2Conditions to Loans.

In addition to the conditions precedent stated elsewhere herein, the Lenders shall not be obligated to make any Loans hereunder unless:

(a)Request. The Borrower shall have timely delivered a duly executed and completed Notice of Borrowing of Term Loans in conformance with all the terms and conditions of this Term Loan Agreement;

(b)Representations and Warranties. The representations and warranties made by the Borrower in the Credit Documents are true and correct in all material respects at and as if made as of the date of the funding of the requested Loans; provided, that this Section 5.2(b) shall not apply to the representations set forth in Sections 6.6, 6.8 and 6.9; and

(c)No Default. On the date of the funding of the requested Loans, no Default or Event of Default has occurred and is continuing or would be caused by making the requested Loans, including, without limitation, the restrictions on (i) the amount of Term Loans that may be outstanding as set forth in Section 2.1 and (ii) the use of proceeds set forth in Section 7.9.

The delivery of each Notice of Borrowing of Term Loans shall constitute a representation and warranty by the Borrower of the correctness of the matters specified in subsections (b) and (c) above.

SECTION 6.REPRESENTATIONS AND WARRANTIES

The Borrower hereby represents and warrants to each Lender that:

6.1Organization and Good Standing.

The Borrower and each Significant Subsidiary (a) is a corporation duly incorporated, validly existing and in good standing under the laws of the jurisdiction of its incorporation, (b) is duly qualified and in good standing as a foreign corporation authorized to do business in every jurisdiction where the failure to so qualify would have a Material Adverse Effect and (c) has the requisite corporate power and authority to own its properties and to carry on its business as now conducted and as proposed to be conducted.

30

6.2Due Authorization.

The Borrower (a) has the requisite corporate power and authority to execute, deliver and perform this Term Loan Agreement and the other Credit Documents and to incur the obligations herein and therein provided for and (b) is duly authorized to, and has been authorized by all necessary corporate action, to execute, deliver and perform this Term Loan Agreement and the other Credit Documents.

6.3No Conflicts.

Neither the execution and delivery of the Credit Documents, nor the consummation of the transactions contemplated therein, nor performance of and compliance with the terms and provisions thereof by the Borrower will (a) violate or conflict with any provision of its certificate or articles of incorporation or bylaws, (b) violate, contravene or materially conflict with any law, regulation (including without limitation, Regulation D, U or X), order, writ, judgment, injunction, decree or permit applicable to it, (c) violate, contravene or materially conflict with contractual provisions of, or cause an event of default under, any indenture, loan agreement, mortgage, deed of trust, contract or other agreement or instrument to which it is a party or by which it may be bound, the violation of which could have a Material Adverse Effect or (d) result in or require the creation of any Lien upon or with respect to its properties.

6.4Consents.

No consent, approval, authorization or order of, or filing, registration or qualification with, any court or Governmental Authority or third party is required in connection with the execution, delivery or performance of this Term Loan Agreement or any of the other Credit Documents that has not been obtained, except for, with respect to any Delayed Draw Term Loans, an additional order of the Federal Energy Regulatory Commission, which order will be obtained (if necessary) prior to, and will be in effect on, the date of any Delayed Draw Term Loans.

6.5Enforceable Obligations.

This Term Loan Agreement and the other Credit Documents have been duly executed and delivered by the Borrower and constitute legal, valid and binding obligations of the Borrower enforceable against the Borrower in accordance with their respective terms, except as may be limited by bankruptcy or insolvency laws or similar laws affecting creditors’ rights generally or by general equitable principles.

6.6Financial Condition.

The financial statements provided to the Lenders as described in Section 5.1(e): (a) fairly present the financial condition and operations of the Borrower as of the date thereof and (b) were prepared in accordance with GAAP.

6.7No Default.

No Default or Event of Default presently exists.

6.8Indebtedness and Off Balance Sheet Indebtedness.

As of the Closing Date, the Borrower and its Subsidiaries have no Indebtedness except as disclosed in the financial statements referenced in Section 5.1(e) and as otherwise incurred in the ordinary course. Set forth on the Borrower’s Annual Report on Form 10‑K for the year ended December 31, 2015

31

is a specific description of all material Off Balance Sheet Indebtedness of the Borrower and its Subsidiaries as of the periods covered thereby.

6.9Litigation.

Except as disclosed in the Borrower’s annual report on Form 10‑K for the year ended December 31, 2015 and in any current report on Form 8-K filed by the Borrower between December 31, 2015 and the Closing Date, there are no actions, suits or legal, equitable, arbitration or administrative proceedings, pending or, to the knowledge of the Borrower, threatened against the Borrower or a Significant Subsidiary, in which there is a reasonable possibility of an adverse decision which has had or would be reasonably expected to have a Material Adverse Effect.

6.10[Reserved]

6.11Taxes.

The Borrower has filed, or caused to be filed, all tax returns (federal, state, local and foreign) required to be filed and paid all amounts of taxes shown thereon to be due (including interest and penalties) and has paid all other taxes, fees, assessments and other governmental charges (including mortgage recording taxes, documentary stamp taxes and intangibles taxes) owing by it, except for such taxes or returns (a) which are not yet delinquent, (b) that are being contested in good faith and by proper proceedings, and against which adequate reserves are being maintained in accordance with GAAP or (c) which are not, either individually or in the aggregate, considered material. The Borrower is not aware of any proposed material tax assessments against it.

6.12Compliance with Law.

The Borrower is in compliance with all laws, rules, regulations, orders and decrees applicable to it, or to its properties, unless (a) such failure to comply would not have a Material Adverse Effect, or (b) the necessity of compliance therewith is being contested in good faith and by proper proceedings.

6.13ERISA.

There have been no ERISA Events that are continuing and either singly or in the aggregate would reasonably be expected to have a Material Adverse Effect. To the knowledge of the Borrower each Pension Plan has been administered with the applicable provisions of ERISA and the Code, and there are no pending, or to the best knowledge of the Borrower, threatened claims, actions or lawsuits, or action by a Governmental Authority, with respect to any Pension Plan (other than claims for benefits and funding obligations in the ordinary course and PBGC premiums due but not delinquent), except where such non-compliance, claim, lawsuit or action either singly or in the aggregate, would not reasonably be expected to have a Material Adverse Effect. No termination of a Pension Plan has occurred, and no Lien in favor of the PBGC or a Pension Plan has arisen, which would reasonably be expected to have a Material Adverse Effect. The present value of all accrued benefits under each Pension Plan (based on those assumptions used to fund such Pension Plan) did not, as of the last annual valuation date prior to the date on which this representation is made or deemed made, exceed the value of the assets of such Pension Plan allocable to such accrued benefits by an amount that could reasonably be expected to have a Material Adverse Effect. The Borrower and each ERISA Affiliate has met all applicable requirements under the Pension Funding Rules with respect to each Pension Plan except where the failure to meet such requirements would not reasonably be expected to have a Material Adverse Effect. Neither the Borrower nor any ERISA Affiliate has had a complete or partial withdrawal from any Multiemployer Plan that has resulted or could reasonably be expected to result in a Material Adverse Effect.

32

6.14Use of Proceeds; Margin Stock.

The proceeds of the Loans hereunder (a) will be used solely for the purposes specified in Section 7.9 and (b) will not be used in a manner that would cause a violation of Regulation U or Regulation X.

6.15Investment Company Act.

The Borrower is not an “investment company” registered or required to be registered under the Investment Company Act of 1940, as amended, or controlled by such a company.

6.16Solvency.

The Borrower is solvent. For purposes of the preceding sentence, “solvent” means (a) the fair saleable value (on a going concern basis) of the Borrower’s assets exceed its liabilities, contingent or otherwise, fairly valued, (b) the Borrower will be able to pay its debts as they become due and (c) upon paying its debts as they become due, the Borrower will not be left with unreasonably small capital as is necessary to satisfy all of its current and reasonably anticipated obligations.

6.17OFAC.

Neither the Borrower, nor any of its Subsidiaries, nor, to the knowledge of the Borrower and its Subsidiaries, any director, officer or employee thereof, is an individual or entity that is, or is owned or controlled by any individual or entity that is (i) currently the subject or target of any Sanctions, (ii) included on OFAC’s List of Specially Designated Nationals or HMT’s Consolidated List of Financial Sanctions Targets and the Investment Ban List or (iii) located, organized or resident in a Designated Jurisdiction.

6.18Anti-Corruption Laws.

To the extent applicable, the Borrower and each of its Subsidiaries conducts its businesses in compliance, in all material respects, with the United States Foreign Corrupt Practices Act of 1977 and the UK Bribery Act 2010 and maintains policies and procedures designed to promote and achieve compliance with such laws.

6.19EEA Financial Institution.

Neither the Borrower nor any of its Subsidiaries is an EEA Financial Institution.

SECTION 7.

AFFIRMATIVE COVENANTS

The Borrower hereby covenants and agrees that so long as this Term Loan Agreement is in effect and until the Loans, together with interest, fees and other obligations hereunder (other than contingent indemnification obligations not yet due and payable), have been paid in full and the Commitments hereunder shall have terminated:

7.1Information Covenants.

The Borrower will furnish, or cause to be furnished, to the Administrative Agent:

33

(a)Annual Financial Statements. As soon as available, and in any event within 120 days after the close of each fiscal year of the Borrower, a consolidated balance sheet and income statement of the Borrower and its Subsidiaries as of the end of such fiscal year, together with related statements of operations and retained earnings and of cash flows for such fiscal year, setting forth in comparative form figures for the preceding fiscal year, all such financial information described above to be in reasonable form and detail and audited by independent certified public accountants of recognized national standing reasonably acceptable to the Administrative Agent and whose opinion shall be to the effect that such financial statements have been prepared in accordance with GAAP (except for changes with which such accountants concur) and shall not be limited as to the scope of the audit or qualified as to going concern. To the extent that the information set forth in this Section 7.1(a) is included in the Borrower’s annual report on Form 10-K as filed with the Securities and Exchange Commission, such information shall be deemed delivered for purposes hereof.

(b)Quarterly Financial Statements. As soon as available, and in any event within 55 days after the close of each fiscal quarter of the Borrower (other than the fourth fiscal quarter) a consolidated balance sheet and income statement of the Borrower and its Subsidiaries as of the end of such fiscal quarter, together with related statements of operations and retained earnings and of cash flows for such fiscal quarter in each case setting forth in comparative form figures for the corresponding period of the preceding fiscal year, all such financial information described above to be in reasonable form and detail and reasonably acceptable to the Administrative Agent, and accompanied by a certificate of the chief financial officer of the Borrower to the effect that such quarterly financial statements fairly present in all material respects the financial condition of the Borrower and its Subsidiaries and have been prepared in accordance with GAAP, subject to changes resulting from audit and normal year‑end audit adjustments. To the extent that the information set forth in this Section 7.1(b) is included in the Borrower’s quarterly report on Form 10-Q as filed with the Securities and Exchange Commission, such information shall be deemed delivered for purposes hereof.

(c)Officer’s Certificate. At the time of delivery of the financial statements provided for in Sections 7.1(a) and 7.1(b) above, a certificate of the chief financial officer, treasurer or any assistant treasurer of the Borrower, substantially in the form of Exhibit 7.1(c), (i) demonstrating compliance with the financial covenant contained in Section 7.11 by calculation thereof as of the end of each such fiscal period and (ii) stating that no Default or Event of Default exists, or if any Default or Event of Default does exist, specifying the nature and extent thereof and what action the Borrower proposes to take with respect thereto.

(d)Notices. Upon a Responsible Officer of the Borrower obtaining knowledge thereof, the Borrower will give written notice to the Administrative Agent as soon as administratively practicable of (i) the occurrence of an event or condition consisting of a Default or Event of Default, specifying the nature and existence thereof and what action the Borrower proposes to take with respect thereto, and (ii) the occurrence of any of the following with respect to the Borrower: (A) the pendency or commencement of any litigation, arbitral or governmental proceeding against the Borrower which, if adversely determined, is likely to have a Material Adverse Effect, (B) the institution of any proceedings against the Borrower with respect to, or the receipt of notice by the Borrower of potential liability or responsibility for, violation or alleged violation of any federal, state or local law, rule or regulation, the violation of which would likely have a Material Adverse Effect or (C) any notice concerning the imposition of any withdrawal liability by a Multiemployer Plan against the Borrower or any of its ERISA Affiliates or the termination of any Pension Plan in a distress termination.

34

(j)Other Information. With reasonable promptness upon any such request, such other information regarding the business, properties or financial condition of the Borrower as the Administrative Agent or any Lender may reasonably request.

Documents required to be delivered pursuant to Section 7.1 (to the extent any such documents are included in materials otherwise filed with the SEC) may be delivered electronically and if so delivered, shall be deemed to have been delivered on the date (i) on which the Borrower posts such documents, or provides a link thereto on the Borrower’s website on the Internet at the website address listed on Schedule 11.1; or (ii) on which such documents are posted on the Borrower’s behalf on an Internet or intranet website, if any, to which each Lender and the Administrative Agent have access (whether a commercial, third‑party website or whether sponsored by the Administrative Agent); provided that: the Borrower shall deliver paper copies of such documents to the Administrative Agent or any Lender upon its request to the Borrower to deliver such paper copies until a written request to cease delivering paper copies is given by the Administrative Agent or such Lender. The Administrative Agent shall have no obligation to request the delivery of or to maintain paper copies of the documents referred to above, and in any event shall have no responsibility to monitor compliance by the Borrower with any such request by a Lender for delivery, and each Lender shall be solely responsible for requesting delivery to it or maintaining its copies of such documents.

The Borrower hereby acknowledges that the Administrative Agent and/or the Arrangers will make available to the Lenders materials and/or information provided by or on behalf of the Borrower hereunder (collectively, “Borrower Materials”) by posting the Borrower Materials on IntraLinks, Syndtrak, Debtdomain and/or DX Syndicate or another similar electronic system (the “Platform”).

7.2Preservation of Existence and Franchises.

The Borrower will, except as permitted by Section 8.2, do all things necessary to preserve and keep in full force and effect its existence, rights, franchises and authority.

7.3Books and Records.

The Borrower will keep complete and accurate books and records of its transactions in accordance with good accounting practices on the basis of GAAP (including the establishment and maintenance of appropriate reserves).

7.4Compliance with Law.

The Borrower will comply with all laws, rules, regulations, orders and decrees, and all restrictions imposed by all Governmental Authorities, applicable to it and its property (a) if noncompliance with any such law, rule, regulation, order or restriction would be reasonably expected to have a Material Adverse Effect or (b) unless the necessity of compliance therewith is being contested in good faith and by proper proceedings.

7.5Payment of Taxes.

The Borrower will pay and discharge all taxes, assessments and governmental charges or levies imposed upon it, or upon its income or profits, or upon any of its properties, before they shall become delinquent; provided, however, that the Borrower shall not be required to pay (a) any such tax, assessment, charge, levy, or claim which is being contested in good faith by appropriate proceedings and as to which adequate reserves therefor have been established in accordance with GAAP or (b) any such taxes which are not, either individually or in the aggregate, considered material.

35

7.6Insurance.

The Borrower will at all times maintain in full force and effect insurance (including worker’s compensation insurance, liability insurance, casualty insurance and business interruption insurance) in such amounts, covering such risks and liabilities and with such deductibles or self-insurance retentions as are in accordance with normal industry practice.

7.7Performance of Obligations.

The Borrower will perform in all material respects all of its obligations under the terms of all material agreements to which it is a party or by which it is bound (other than agreements, indentures, mortgages, security agreements or other instruments relating to Indebtedness) unless (i) Borrower’s nonperformance of any such agreement would not reasonably be expected to have a Material Adverse Effect or (ii) the necessity of performance thereof is being contested in good faith and by proper proceedings.

7.8ERISA.

The Borrower shall, and shall, to the extent practicable, cause each of its ERISA Affiliates to: (a) maintain each Pension Plan in compliance with the applicable provisions of ERISA, the Code and other applicable federal or state law; and (b) make all required contributions to any Pension Plan subject to Section 412 or Section 430 of the Code and all contributions required of the Borrower and its ERISA Affiliates to any Multiemployer Plan subject to Section 431 of the Code; except in each such instance in clause (a) or (b) where the failure to do so, either singly or in the aggregate, would not reasonably be expected to have a Material Adverse Effect.

7.9Use of Proceeds.

The proceeds of the Term Loans shall be used solely to repay existing indebtedness, including the Existing Term Loan Agreements, and for other general corporate purposes.

7.10Audits/Inspections.

Upon reasonable notice and during normal business hours, the Borrower will permit representatives appointed by the Administrative Agent, including, without limitation, independent accountants, agents, attorneys, and appraisers to visit and inspect the Borrower’s property, including its books and records, its accounts receivable and inventory, the Borrower’s facilities and its other business assets, and to make photocopies or photographs thereof and to write down and record any information such representative obtains and shall permit the Administrative Agent or its representatives to investigate and verify the accuracy of information provided to the Lenders and to discuss all such matters with the officers, employees and representatives of the Borrower. So long as there is not a Default or Event of Default or unless Borrower otherwise consents, such visits and inspections shall be limited to once per calendar year.

7.11Indebtedness to Capitalization.

The ratio of (a) Indebtedness of the Borrower and its consolidated Subsidiaries to (b) Capitalization shall at all times be less than or equal to 0.65 to 1.0.

36

SECTION 8.

NEGATIVE COVENANTS

The Borrower hereby covenants and agrees that so long as this Term Loan Agreement is in effect and until the Loans, together with interest, fees and other obligations hereunder (other than contingent indemnification obligations not yet due and payable), have been paid in full and the Commitments hereunder shall have terminated:

8.1Nature of Business.

The Borrower will not alter the character of its business from that conducted as of the Closing Date.

8.2Consolidation and Merger.

The Borrower will not enter into any transaction of merger or consolidation or liquidate, wind up or dissolve itself (or suffer any liquidation or dissolution); provided that notwithstanding the foregoing provisions of this Section 8.2, the following actions may be taken if after giving effect thereto no Default or Event of Default exists:

(a)a Subsidiary of the Borrower may be merged or consolidated with or into the Borrower; provided that the Borrower shall be the continuing or surviving corporation; and

(b)the Borrower may merge or consolidate with any other Person (other than one of its Subsidiaries) if either (i) the Borrower shall be the continuing or surviving corporation or (ii) the Borrower shall not be the continuing or surviving corporation and the corporation so continuing or surviving (A) is a corporation organized and duly existing under the law of any state of the United States, (B) has (1) a long term, senior, unsecured, non-credit enhanced debt rating of BBB- or better from S&P and Baa3 or better from Moody’s or (2) a commercial paper rating of A-2 or better from S&P and P-2 or better from Moody’s and (C) executes and delivers to the Administrative Agent and the Lenders an instrument in form reasonably satisfactory to the Required Lenders pursuant to which it expressly assumes the Loans and all of the other obligations of the Borrower under the Credit Documents and procures for the Administrative Agent and each Lender an opinion in form reasonably satisfactory to the Required Lenders in respect of the due authorization, execution, delivery and enforceability of such instrument and covering such other matters as the Required Lenders may reasonably request; provided that prior to any such merger or consolidation, the Borrower shall have delivered to the Administrative Agent a certificate demonstrating that, upon giving effect to such merger or consolidation on a pro forma basis, the Borrower will be in compliance with Section 7.11.

8.3Sale or Lease of Assets.

Except as permitted by Section 8.2, the Borrower will not convey, sell, lease, transfer or otherwise dispose of in one transaction or a series of transactions, all or substantially all of its business or assets whether now owned or hereafter acquired.

8.4Transactions with Affiliates.

Except as otherwise required by law, the Borrower will not enter into any transaction or series of transactions, whether or not in the ordinary course of business, with any of its Affiliates other than on

37

terms and conditions substantially as favorable as would be obtainable in a comparable arm’s‑length transaction with a Person other than an Affiliate.

8.5Fiscal Year.

The Borrower will not change its fiscal year (a) without prior written notification to the Lenders and (b) if such change would materially affect the Lenders’ ability to read and interpret the financial statements delivered pursuant to Section 7.1 or calculate the financial covenant in Section 7.11.

8.6Liens.

The Borrower will not contract, create, incur, assume or permit to exist any Lien with respect to any of its property or assets of any kind (whether real or personal, tangible or intangible), whether now owned or hereafter acquired, securing any Indebtedness unless the Loans hereunder are equally and ratably secured with such other Indebtedness other than the following: (a) Liens securing Borrower Obligations, (b) Liens for taxes not yet due or Liens for taxes being contested in good faith by appropriate proceedings for which adequate reserves determined in accordance with GAAP have been established (and as to which the property subject to any such Lien is not yet subject to foreclosure, sale or loss on account thereof), (c) Liens in respect of property imposed by law arising in the ordinary course of business such as materialmen’s, mechanics’, warehousemen’s, carrier’s, landlords’ and other nonconsensual statutory Liens which are not yet due and payable, which have been in existence less than 90 days or which are being contested in good faith by appropriate proceedings for which adequate reserves determined in accordance with GAAP have been established (and as to which the property subject to any such Lien is not yet subject to foreclosure, sale or loss on account thereof), (d) pledges or deposits made in the ordinary course of business to secure payment of worker’s compensation insurance, unemployment insurance, pensions or social security programs, (e) Liens arising from good faith deposits in connection with or to secure performance of tenders, bids, leases, government contracts, performance and return-of-money bonds and other similar obligations incurred in the ordinary course of business (other than obligations in respect of the payment of borrowed money), (f) Liens arising from good faith deposits in connection with or to secure performance of statutory obligations and surety and appeal bonds (unless such Lien is in connection with a judgment that has caused an Event of Default pursuant to Section 9.1(g)), (g) easements, rights-of-way, restrictions (including zoning restrictions), minor defects or irregularities in title and other similar charges or encumbrances not, in any material respect, impairing the use of the encumbered property for its intended purposes, (h) judgment Liens that would not constitute an Event of Default, (i) Liens arising by virtue of any statutory or common law provision relating to banker’s liens, rights of setoff or similar rights as to deposit accounts or other funds maintained with a creditor depository institution, (j) any Lien created or arising over any property which is acquired, constructed or created by the Borrower, but only if (i) such Lien secures only principal amounts (not exceeding the cost of such acquisition, construction or creation) raised for the purposes of such acquisition, construction or creation, together with any costs, expenses, interest and fees incurred in relation thereto or a guarantee given in respect thereof, (ii) such Lien is created or arises on or before 360 days after the completion of such acquisition, construction or creation and (iii) such Lien is confined solely to the property so acquired, constructed or created and any improvements thereto, (k) any Lien on any property or assets acquired from a corporation or other entity which is merged with or into the Borrower in accordance with Section 8.2, and is not created in anticipation of any such transaction (unless such Lien is created to secure or provide for the payment of any part of the purchase price of such corporation or other entity), (l) any Lien on any property or assets existing at the time of acquisition of such property or assets by the Borrower and which is not created in anticipation of such acquisition (unless such Lien was created to secure or provide for the payment of any part of the purchase price of such property or assets) including, but not limited to, the Liens associated with the revenue bonds assumed by the Borrower in connection with the acquisition of the combined cycle units at Plant Daniel, (m) any extension, renewal

38

or replacement (or successive extensions, renewals or replacements), as a whole or in part, of any Liens referred to in the foregoing clauses (a) through (l), for amounts not exceeding the principal amount of the Indebtedness secured by the Lien so extended, renewed or replaced, provided that such extension, renewal or replacement Lien is limited to all or a part of the same property or assets that were covered by the Lien extended, renewed or replaced (plus improvements on such property or assets), (n) any Lien arising in connection with the issuance of Rate Reduction Bonds and (o) Liens on property, in addition to those otherwise permitted by clauses (a) through (n) above, securing, directly or indirectly, Indebtedness which does not exceed, in the aggregate at any one time outstanding, the greater of (i) $100,000,000.00 or (ii) ten percent (10%) of Net Tangible Assets.

8.7Sanctions.

The Borrower shall not, directly or, to the knowledge of the Borrower, indirectly, use any Loans or the proceeds of any Loans, or lend, contribute or otherwise make available such Loans or the proceeds of any Loans to any Person, to fund any activities of or business with any Person, or in any Designated Jurisdiction, that, at the time of such funding, is the subject of Sanctions, or in any other manner that will, to the knowledge of the Borrower, result in a violation by any Person (including any Person participating in the transaction, whether as Lender, Arranger, Administrative Agent, or otherwise) of Sanctions.

8.8Anti-Corruption Laws.

The Borrower shall not, directly or indirectly, use the proceeds of any Loans for any purpose which would breach the United States Foreign Corrupt Practices Act of 1977 or the UK Bribery Act 2010.

SECTION 9.

EVENTS OF DEFAULT

9.1Events of Default.

An Event of Default shall exist upon the occurrence of any of the following specified events (each an “Event of Default”):

(a)Payment. The Borrower shall:

(i)default in the payment when due of any principal of any of the Loans; or

(ii)default, and such default shall continue for five or more Business Days, in the payment when due of any interest on the Loans or of any fees or other amounts owing hereunder, under any of the other Credit Documents or in connection herewith.

(b)Representations. Any representation, warranty or statement made or deemed to be made by the Borrower herein, in any of the other Credit Documents, or in any statement or certificate delivered or required to be delivered pursuant hereto or thereto shall prove untrue in any material respect on the date as of which it was made or deemed to have been made; provided, however, that if such untrue representation, warranty or statement is capable of being remedied, it shall not be an Event of Default if the Borrower remedies such untrue representation, warranty or statement within ten (10) Business Days of any Responsible Officer of the Borrower obtaining actual knowledge thereof.

39

(c)Covenants. The Borrower shall:

(i)default in the due performance or observance of any term, covenant or agreement contained in Sections 7.2, 7.3, 7.4, 7.9, 7.11 or 8.1 through 8.8, inclusive; or

(ii)default in the due performance or observance by it of any term, covenant or agreement contained in Section 7.1(a), (b), (c) or (d) and such default shall continue unremedied for a period of ten Business Days after the earlier of an officer of the Borrower becoming aware of such default or written notice thereof given by the Administrative Agent; or

(iii)default in the due performance or observance by it of any term, covenant or agreement (other than those referred to in subsections (a), (b), (c)(i) or (c)(ii) of this Section 9.1) contained in this Term Loan Agreement or any other Credit Document and such default shall continue unremedied for a period of at least 30 days after the earlier of an officer of the Borrower becoming aware of such default or written notice thereof given by the Administrative Agent.

(d)Credit Documents. Any Credit Document shall fail to be in full force and effect or to give the Administrative Agent and/or the Lenders the rights, powers and privileges purported to be created thereby.

(e)Bankruptcy, etc. The occurrence of any of the following with respect to the Borrower or a Significant Subsidiary: (i) a court or governmental agency having jurisdiction in the premises shall enter a decree or order for relief in respect of the Borrower or a Significant Subsidiary in an involuntary case under any applicable bankruptcy, insolvency or other similar law now or hereafter in effect, or appoint a receiver, liquidator, assignee, custodian, trustee, sequestrator or similar official of the Borrower or a Significant Subsidiary or for any substantial part of its property or ordering the winding up or liquidation of its affairs; or (ii) an involuntary case under any applicable bankruptcy, insolvency or other similar law now or hereafter in effect is commenced against the Borrower or a Significant Subsidiary and such petition remains unstayed and in effect for a period of 60 consecutive days; or (iii) the Borrower or a Significant Subsidiary shall commence a voluntary case under any applicable bankruptcy, insolvency or other similar law now or hereafter in effect, or consent to the entry of an order for relief in an involuntary case under any such law, or consent to the appointment or taking possession by a receiver, liquidator, assignee, custodian, trustee, sequestrator or similar official of such Person or any substantial part of its property or make any general assignment for the benefit of creditors; or (iv) the Borrower or a Significant Subsidiary shall admit in writing its inability to pay its debts generally as they become due or any action shall be taken by such Person in furtherance of any of the aforesaid purposes.

(f)Defaults under Other Agreements. With respect to any Indebtedness (other than the Indebtedness under this Term Loan Agreement) of the Borrower or a Significant Subsidiary in a principal amount in excess of $100,000,000, (i) the Borrower or such Significant Subsidiary shall (A) default in any payment (interest or principal) (beyond the applicable grace period with respect thereto, if any) with respect to any such Indebtedness, or (B) default (after giving effect to any applicable grace period) in the observance or performance of any covenant or agreement relating to such Indebtedness or contained in any instrument or agreement evidencing, securing or relating thereto, or any other event or condition shall occur or condition exist, the effect of which default pursuant to this clause (B) or other event or condition is to cause, any such Indebtedness to become immediately due and payable; or (ii) any such Indebtedness shall be declared due and

40

payable, or required to be prepaid other than by a regularly scheduled required prepayment, prior to the stated maturity thereof; or (iii) any such Indebtedness matures and remains unpaid.

(g)Judgments. One or more judgments, orders, or decrees shall be entered against the Borrower or a Significant Subsidiary involving a liability of $100,000,000 or more, in the aggregate, (to the extent not paid or covered by insurance provided by a carrier who has acknowledged coverage) and such judgments, orders or decrees shall continue unsatisfied, undischarged and unstayed for a period of at least 30 days after the last day on which such judgment, order or decree becomes final and unappealable and, where applicable, with the status of a judicial lien.

(h)ERISA. (i) An ERISA Event occurs which is continuing and has resulted or would reasonably be expected to result in liability of the Borrower or any ERISA Affiliate in an aggregate amount in excess of $100,000,000, or (ii) the Borrower or any ERISA Affiliate fails to pay when due, after the expiration of any applicable grace period, any installment payment with respect to its withdrawal liability under Section 4201 of ERISA under a Multiemployer Plan in an aggregate amount in excess of $100,000,000; or

(i)Change of Control. The occurrence of any Change of Control.

9.2Acceleration; Remedies.

Upon the occurrence of an Event of Default, and at any time thereafter unless and until such Event of Default has been waived by the Required Lenders (or the Lenders, if required by Section 11.6) or cured to the satisfaction of the Required Lenders (or the Lenders, if required by Section 11.6), the Administrative Agent may with the consent of the Required Lenders, and shall, upon the request and direction of the Required Lenders by written notice to the Borrower, take any of the following actions without prejudice to the rights of the Administrative Agent or any Lender to enforce its claims against the Borrower, except as otherwise specifically provided for herein:

(i)Termination of Commitments. Declare the Commitments terminated whereupon the Commitments shall be immediately terminated.

(ii)Acceleration of Loans. Declare the unpaid principal of and any accrued interest in respect of all Loans and any and all other indebtedness or obligations of any and every kind owing by the Borrower to any of the Lenders or the Administrative Agent hereunder to be due whereupon the same shall be immediately due and payable without presentment, demand, protest or other notice of any kind, all of which are hereby waived by the Borrower.

(iii)Enforcement of Rights. Enforce any and all rights and interests created and existing under the Credit Documents, including, without limitation, all rights of set-off.

Notwithstanding the foregoing, if an Event of Default specified in Section 9.1(e) shall occur, then (a) the Commitments shall automatically terminate and (b) all Loans, all accrued interest in respect thereof, all accrued and unpaid fees and other indebtedness or obligations owing to the Lenders and the Administrative Agent hereunder shall immediately become due and payable, without the giving of any notice or other action by the Administrative Agent or the Lenders.

41

Notwithstanding the fact that enforcement powers reside primarily with the Administrative Agent, each Lender has, to the extent permitted by law, a separate right of payment and shall be considered a separate “creditor” holding a separate “claim” within the meaning of Section 101(5) of the Bankruptcy Code or any other insolvency statute.

9.3Allocation of Payments after Event of Default.

Notwithstanding any other provisions of this Term Loan Agreement, after the exercise of any remedies by the Administrative Agent or the Lenders pursuant to Section 9.2 (or after the Commitments shall automatically terminate and the Loans (with accrued interest thereon) and all other amounts under the Credit Documents shall automatically become due and payable in accordance with the terms of such Section), all amounts collected or received by the Administrative Agent or any Lender on account of amounts outstanding under any of the Credit Documents shall be paid over or delivered as follows:

FIRST, to the payment of all reasonable out‑of‑pocket costs and expenses (including without limitation reasonable attorneys’ fees) of the Administrative Agent or any of the Lenders in connection with enforcing the rights of the Lenders under the Credit Documents and any protective advances made by the Administrative Agent or any of the Lenders, pro rata among them in proportion to the respective amounts described in this clause FIRST owed to them;

SECOND, to payment of any fees owed to the Administrative Agent or any Lender, pro rata among them in proportion to the respective amounts described in this clause SECOND owed to them;

THIRD, to the payment of all accrued interest payable on the Loans and other Borrower Obligations to the Lenders hereunder, pro rata among them in proportion to the respective amounts described in this clause THIRD owed to them;

FOURTH, to the payment of the outstanding principal amount of the Loans and all other Borrower Obligations which shall have become due and payable under the Credit Documents, pro rata among the Lenders in proportion to the respective amounts described in this clause FOURTH held by them; and

FIFTH, the payment of the surplus, if any, to whoever may be lawfully entitled to receive such surplus.

In carrying out the foregoing, (a) amounts received shall be applied in the numerical order provided until exhausted prior to application to the next succeeding category and (b) each of the Lenders shall receive an amount equal to its pro rata share (based on the proportion that the then outstanding Loans held by such Lender bears to the aggregate then outstanding Loans) of amounts available to be applied.

SECTION 10.AGENCY PROVISIONS

10.1Appointment.

Each Lender hereby designates and appoints Bank of America, N.A., as Administrative Agent to act as specified herein and the other Credit Documents, and each such Lender hereby authorizes the Administrative Agent, as an agent for such Lender, to take such action on its behalf under the provisions of this Term Loan Agreement and the other Credit Documents and to exercise such powers and perform such duties as are expressly delegated by the terms hereof and of the other Credit Documents, together

42

with such other powers as are reasonably incidental thereto. Notwithstanding any provision to the contrary elsewhere herein and in the other Credit Documents, the Administrative Agent shall not have any duties or responsibilities, except those expressly set forth herein and therein, or any fiduciary relationship with any Lender, and no implied covenants, functions, responsibilities, duties, obligations or liabilities shall be read into this Term Loan Agreement or any of the other Credit Documents, or shall otherwise exist against the Administrative Agent. Except as expressly set forth herein, the provisions of this Section 10 are solely for the benefit of the Administrative Agent and the Lenders and the Borrower shall not have any rights as a third party beneficiary of the provisions hereof. In performing its functions and duties under this Term Loan Agreement and the other Credit Documents, the Administrative Agent shall act solely as an agent of the Lenders and does not assume and shall not be deemed to have assumed any obligation or relationship of agency or trust with or for the Borrower. Notwithstanding anything herein or in any of the Credit Documents to the contrary, no Lender that is listed as a Syndication Agent, Co-Documentation Agent, a Co-Managing Agent or Co-Agent (if any) herein shall have any functions, duties, obligations, responsibilities or liabilities, or serve in any capacity, hereunder or under any of the Credit Documents except as a Lender in accordance with the terms of the Credit Documents. The Administrative Agent shall, upon receipt thereof, from the Borrower, promptly deliver to the Lenders copies of the financial statements, certificates and other notices received pursuant to Section 7.1.

10.2Delegation of Duties.

The Administrative Agent may execute any of its duties hereunder or under the other Credit Documents by or through agents or attorneys-in-fact and shall be entitled to advice of counsel concerning all matters pertaining to such duties. The Administrative Agent shall not be responsible for the negligence or misconduct of any agents or attorneys-in-fact selected by it with reasonable care.

10.3Exculpatory Provisions.

No Agent-Related Person shall be (a) liable for any action lawfully taken or omitted to be taken by it or such Person under or in connection herewith or in connection with any of the other Credit Documents (except for its or such Person’s own gross negligence or willful misconduct) or (b) responsible in any manner to any of the Lenders for any recitals, statements, representations or warranties made by the Borrower contained herein or in any of the other Credit Documents or in any certificate, report, statement or other document referred to or provided for in, or received by an Agent-Related Person under or in connection herewith or in connection with the other Credit Documents, or enforceability or sufficiency therefor of any of the other Credit Documents, or for any failure of the Borrower to perform its obligations hereunder or thereunder. No Agent-Related Person shall be responsible to any Lender for the effectiveness, genuineness, validity, enforceability, collectability or sufficiency of this Term Loan Agreement, or any of the other Credit Documents or for any representations, warranties, recitals or statements made herein or therein or made by the Borrower in any written or oral statement or in any financial or other statements, instruments, reports, certificates or any other documents in connection herewith or therewith furnished or made by an Agent-Related Person to the Lenders or by or on behalf of the Borrower to an Agent-Related Person or any Lender or be required to ascertain or inquire as to the performance or observance of any of the terms, conditions, provisions, covenants or agreements contained herein or therein or as to the use of the proceeds of the Loans or of the existence or possible existence of any Default or Event of Default or to inspect the properties, books or records of the Borrower. The Administrative Agent is not a trustee for the Lenders and owes no fiduciary duty to the Lenders.

The Administrative Agent shall not have any duty to take any discretionary action or exercise any discretionary powers, except discretionary rights and powers expressly contemplated hereby or by the other Credit Documents that the Administrative Agent is required to exercise as directed in writing by the Required Lenders (or such other number or percentage of the Lenders as shall be expressly provided for

43

herein or in the other Credit Documents), provided that the Administrative Agent shall not be required to take any action that, in its opinion or the opinion of its counsel, may expose the Administrative Agent to liability or that is contrary to any Credit Document or applicable Law.

10.4Reliance on Communications.

The Administrative Agent shall be entitled to rely, and shall be fully protected in relying, upon any note, writing, resolution, notice, consent, certificate, affidavit, letter, cablegram, telegram, telecopy, telex or teletype message, statement, order or other document or conversation believed by it to be genuine and correct and to have been signed, sent or made by the proper Person or Persons and upon advice and statements of legal counsel (including, without limitation, counsel to the Borrower, independent accountants and other experts selected by the Administrative Agent with reasonable care). The Administrative Agent may deem and treat the Lenders as the owner of its interests hereunder for all purposes unless a written notice of assignment, negotiation or transfer thereof shall have been filed with the Administrative Agent in accordance with Section 11.3(b). The Administrative Agent shall be fully justified in failing or refusing to take any action under this Term Loan Agreement or under any of the other Credit Documents unless it shall first receive such advice or concurrence of the Required Lenders as it deems appropriate or it shall first be indemnified to its satisfaction by the Lenders against any and all liability and expense which may be incurred by it by reason of taking or continuing to take any such action. The Administrative Agent shall in all cases be fully protected in acting, or in refraining from acting, hereunder or under any of the other Credit Documents in accordance with a request of the Required Lenders (or, to the extent specifically provided in Section 11.6, all the Lenders) and such request and any action taken or failure to act pursuant thereto shall be binding upon all the Lenders (including their successors and assigns).

10.5Notice of Default.

The Administrative Agent shall not be deemed to have knowledge or notice of the occurrence of any Default or Event of Default hereunder unless it has received notice from a Lender or the Borrower referring to the Credit Documents, describing such Default or Event of Default and stating that such notice is a “notice of default.” In the event that the Administrative Agent receives such a notice, the Administrative Agent shall give prompt notice thereof to the Lenders. The Administrative Agent shall take such action with respect to such Default or Event of Default as shall be directed by the Required Lenders.

10.6Non-Reliance on Administrative Agent and Other Lenders.

Each Lender expressly acknowledges that no Agent‑Related Person has made any representations or warranties to it and that no act by any Agent‑Related Person hereinafter taken, including any review of the affairs of the Borrower, shall be deemed to constitute any representation or warranty by any Agent‑Related Person to any Lender. Each Lender represents to the Administrative Agent that it has, independently and without reliance upon the Administrative Agent, any Agent‑Related Person or any Lender, and based on such documents and information as it has deemed appropriate, made its own appraisal of and investigation into the business, assets, operations, property, financial and other conditions, prospects and creditworthiness of the Borrower and made its own decision to make its Loans hereunder and enter into this Term Loan Agreement. Each Lender also represents that it will, independently and without reliance upon the Administrative Agent, any Agent‑Related Person or any Lender, and based on such documents and information as it shall deem appropriate at the time, continue to make its own credit analysis, appraisals and decisions in taking or not taking action under this Term Loan Agreement, and to make such investigation as it deems necessary to inform itself as to the business, assets, operations, property, financial and other conditions, prospects and creditworthiness of the

44

Borrower. Except for (i) delivery of the Credit Documents, (ii) delivery of all financial statements received by the Administrative Agent pursuant to Section 7.1(a) and 7.1(b) and each report received by the Administrative Agent pursuant to Section 7.1(c), (iii) delivery of all notices received by the Administrative Agent pursuant to Sections 7.1(d), 7.1(e) and 7.8 and (iv) delivery of notices, reports and other documents expressly required to be furnished to the Lenders by the Administrative Agent hereunder, no Agent‑Related Person shall have any duty or responsibility to provide any Lender with any credit or other information concerning the business, operations, assets, property, financial or other conditions, prospects or creditworthiness of the Borrower which may come into the possession of an Agent‑Related Person.

10.7Indemnification.

Each Lender agrees to indemnify each Agent-Related Person (to the extent not reimbursed by the Borrower and without limiting the obligation of the Borrower to do so), ratably according to such Lender’s Commitment in effect on the date on which indemnification is sought under this section (or if indemnification is sought after the date on which the Commitments shall have terminated and the Loans shall have been paid in full, according to such Lender’s Commitment in effect immediately prior to such date), from and against any and all liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements of any kind whatsoever which may at any time (including without limitation at any time following the payment of the Borrower Obligations) be imposed on, incurred by or asserted against such Agent-Related Person in any way relating to or arising out of this Term Loan Agreement or the other Credit Documents or any documents contemplated by or referred to herein or therein or the transactions contemplated hereby or thereby or any action taken or omitted by such Agent-Related Person under or in connection with any of the foregoing; provided that no Lender shall be liable for the payment of any portion of such liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements resulting from the gross negligence or willful misconduct of such Agent-Related Person. If any indemnity furnished to an Agent-Related Person for any purpose shall, in the opinion of such Agent-Related Person, be insufficient or become impaired, such Agent-Related Person may call for additional indemnity and cease, or not commence, to do the acts indemnified against until such additional indemnity is furnished. The agreements in this Section 10.7 shall survive the payment of the Borrower Obligations and all other amounts payable hereunder and under the other Credit Documents.

10.8Administrative Agent in Its Individual Capacity.

The Administrative Agent and its Affiliates may make loans to, accept deposits from and generally engage in any kind of business with the Borrower as though the Administrative Agent were not Administrative Agent hereunder. With respect to the Loans made and all Borrower Obligations owing to it, the Administrative Agent shall have the same rights and powers under this Term Loan Agreement as any Lender and may exercise the same as though they were not the Administrative Agent, and the terms “Lender” and “Lenders” shall include the Administrative Agent in its individual capacity.

10.9Successor Administrative Agent.

The Administrative Agent may, at any time, resign upon 30 days written notice to the Borrower and the Lenders. Upon any such resignation, the Required Lenders, with the written consent of the Borrower, shall have the right to appoint a successor to the resigning Administrative Agent. If no successor Administrative Agent shall have been so duly appointed, and/or such successor agent shall not have accepted such appointment, within 30 days after the notice of resignation (the “Resignation Effective Date”), then the retiring Administrative Agent may (but shall not be obligated to) select a successor Administrative Agent, with the written consent of the Borrower, provided such successor is a

45

Lender hereunder or a commercial bank organized or licensed under the laws of the United States of America or of any State thereof and has a combined capital and surplus of at least $5,000,000,000. Whether or not a successor has been appointed, such resignation shall become effective in accordance with such notice on the Resignation Effective Date. If no successor Administrative Agent shall have been appointed in the time frame set forth above, then the Lenders shall perform all the obligations of the resigning Administrative Agent until the time a successor has been appointed by the Required Lenders, with the written consent of the Borrower, as set forth above and has accepted such appointment. If at any time it is determined that the Administrative Agent is a Defaulting Lender for purposes hereof, the Borrower may request, subject to the written consent of the Required Lenders, that the Administrative Agent be replaced with a successor administrative agent by notifying the Lenders in writing of its nomination of a current Lender to act as the administrative agent hereunder. The nominated Lender shall be appointed as the successor administrative agent upon approval of the nomination by the Required Lenders; provided, however, that any Lender’s failure to respond to the Borrower’s nomination within ten (10) days of receipt of such nomination shall be deemed to be such Lender’s approval thereof. Upon the acceptance of the appointment as Administrative Agent hereunder by a successor, such successor Administrative Agent shall thereupon succeed to and become vested with all the rights, powers, privileges and duties of the retiring Administrative Agent, and the retiring Administrative Agent shall be discharged from its duties and obligations as Administrative Agent under this Term Loan Agreement and the other Credit Documents and the provisions of this Section 10 shall inure to its benefit as to any actions taken or omitted to be taken by it while it was the Administrative Agent under this Term Loan Agreement.

If at any time any existing Lender shall cease to be a Lender hereunder, such institution shall be discharged from all of its respective duties and obligations hereunder or under the other Credit Documents in that capacity.

10.10Administrative Agent May File Proof of Claims.

In case of the pendency of any receivership, insolvency, liquidation, bankruptcy, reorganization, arrangement, adjustment, composition or other judicial proceeding relative to the Borrower, the Administrative Agent (irrespective of whether the principal of any Loan shall then be due and payable as herein expressed or by declaration or otherwise and irrespective of whether the Administrative Agent shall have made any demand on the Borrower) shall be entitled and empowered, by intervention in such proceeding or otherwise:

(a)to file and prove a claim for the whole amount of the principal and interest owing and unpaid in respect of the Loans and all other Borrower Obligations that are owing and unpaid and to file such other documents as may be necessary or advisable in order to have the claims of the Lenders and the Administrative Agent (including any claim for the reasonable compensation, expenses, disbursements and advances of the Lenders and the Administrative Agent and their respective agents and counsel and all other amounts due the Lenders and the Administrative Agent under Sections 3.4 and 11.5 allowed in such judicial proceeding); and

(b)to collect and receive any monies or other property payable or deliverable on any such claims and to distribute the same;

and any custodian, receiver, assignee, trustee, liquidator, sequestrator or other similar official in any such judicial proceeding is hereby authorized by each Lender to make such payments to the Administrative Agent and, in the event that the Administrative Agent shall consent to the making of such payments directly to the Lenders, to pay to the Administrative Agent any amount due for the reasonable compensation, expenses, disbursements and advances of the Administrative Agent and its agents and counsel, and any other amounts due the Administrative Agent under Sections 3.4 and 11.5.

46

Nothing contained herein shall be deemed to authorize the Administrative Agent to authorize or consent to or accept or adopt on behalf of any Lender any plan of reorganization, arrangement, adjustment or composition affecting the Borrower Obligations or the rights of any Lender or to authorize the Administrative Agent to vote in respect of the claim of any Lender in any such proceeding.

SECTION 11.MISCELLANEOUS

11.1Notices and other Communications; Facsimile Copies.

(a)Notices Generally. Except in the case of notices and other communications expressly permitted to be given by telephone (and except as provided in subsection (b) below), all notices and other communications provided for herein shall be in writing and shall be delivered by hand or overnight courier service, mailed by certified or registered mail or sent by telecopier as follows, and all notices and other communications expressly permitted hereunder to be given by telephone shall be made to the applicable telephone number, as follows:

(i)if to the Borrower or the Administrative Agent, to the address, telecopier number, electronic mail address or telephone number specified for such Person on Schedule 11.1; and

(ii)if to any other Lender, to the address, telecopier number, electronic mail address or telephone number specified in its Administrative Questionnaire (including, as appropriate, notices delivered solely to the Person designated by a Lender on its Administrative Questionnaire then in effect for the delivery of notices that may contain material non-public information relating to the Borrower).

Notices and other communications sent by hand or overnight courier service, or mailed by certified or registered mail, shall be deemed to have been given when received; notices and other communications sent by telecopier shall be deemed to have been given when sent (except that, if not given during normal business hours for the recipient, shall be deemed to have been given at the opening of business on the next business day for the recipient). Notices and other communications delivered through electronic communications to the extent provided in subsection (b) below, shall be effective as provided in such subsection (b).

(b)Electronic Communications. Notices and other communications to the Lenders hereunder may be delivered or furnished by electronic communication (including e‑mail and Internet or intranet websites) pursuant to procedures approved by the Administrative Agent, provided that the foregoing shall not apply to notices to any Lender pursuant to Article II if such Lender has notified the Administrative Agent that it is incapable of receiving notices under such Article by electronic communication. The Administrative Agent or the Borrower may, in its discretion, agree to accept notices and other communications to it hereunder by electronic communications pursuant to procedures approved by it, provided that approval of such procedures may be limited to particular notices or communications.

Unless the Administrative Agent otherwise prescribes, (i) notices and other communications sent to an e-mail address shall be deemed received upon the sender’s receipt of an acknowledgement from the intended recipient (such as by the “return receipt requested” function, as available, return e-mail or other written acknowledgement), provided that if such notice or other communication is not sent during the normal business hours of the recipient, such notice or communication shall be deemed to have been sent

47

at the opening of business on the next business day for the recipient, and (ii) notices or communications posted to an Internet or intranet website shall be deemed received upon the deemed receipt by the intended recipient at its e-mail address as described in the foregoing clause (i) of notification that such notice or communication is available and identifying the website address therefor.

The words “execute,” “execution,” “signed,” “signature,” and words of like import in or related to any document to be signed in connection with this Agreement, any other document executed in connection herewith and the transactions contemplated hereby (including without limitation Assignment and Assumptions, amendments or other modifications, Notices of Borrowing of Term Loans, waivers and consents) shall be deemed to include electronic signatures, the electronic matching of assignment terms and contract formations on electronic platforms approved by the Administrative Agent, or the keeping of records in electronic form, each of which shall be of the same legal effect, validity or enforceability as a manually executed signature, physical delivery or the use of a paper-based recordkeeping system, as the case may be, to the extent and as provided for in any applicable Law, including the Federal Electronic Signatures in Global and National Commerce Act, the New York State Electronic Signatures and Records Act, or any other similar state laws based on the Uniform Electronic Transactions Act; provided that notwithstanding anything contained herein to the contrary the Administrative Agent is under no obligation to agree to accept electronic signatures in any form or in any format unless expressly agreed to by the Administrative Agent pursuant to procedures approved by it; provided further without limiting the foregoing, upon the request of any party, any electronic signature shall be promptly followed by such manually executed counterpart.

(c)The Platform. THE PLATFORM IS PROVIDED “AS IS” AND “AS AVAILABLE.” THE AGENT PARTIES (AS DEFINED BELOW) DO NOT WARRANT THE ACCURACY OR COMPLETENESS OF BORROWER MATERIALS OR THE ADEQUACY OF THE PLATFORM, AND EXPRESSLY DISCLAIM LIABILITY FOR ERRORS IN OR OMISSIONS FROM THE BORROWER MATERIALS. NO WARRANTY OF ANY KIND, EXPRESS, IMPLIED OR STATUTORY, INCLUDING ANY WARRANTY OF MERCHANTABILITY, FITNESS FOR A PARTICULAR PURPOSE, NON-INFRINGEMENT OF THIRD PARTY RIGHTS OR FREEDOM FROM VIRUSES OR OTHER CODE DEFECTS, IS MADE BY ANY AGENT PARTY IN CONNECTION WITH THE BORROWER MATERIALS OR THE PLATFORM. In no event shall the Administrative Agent or any of its Related Parties (collectively, the “Agent Parties”) have any liability to the Borrower, any Lender or any other Person for losses, claims, damages, liabilities or expenses of any kind (whether in tort, contract or otherwise) arising out of the Borrower’s or the Administrative Agent’s transmission of Borrower Materials through the Internet, except to the extent that such losses, claims, damages, liabilities or expenses are determined by a court of competent jurisdiction by a final and nonappealable judgment to have resulted from the gross negligence or willful misconduct of such Agent Party; provided, however, that in no event shall any Agent Party have any liability to the Borrower, any Lender or any other Person for indirect, special, incidental, consequential or punitive damages (as opposed to direct or actual damages).

(d)Change of Address, Etc. Each of the Borrower and the Administrative Agent may change its address, telecopier or telephone number for notices and other communications hereunder by notice to the other parties hereto. Each other Lender may change its address, telecopier or telephone number for notices and other communications hereunder by notice to the Borrower and the Administrative Agent. In addition, each Lender agrees to notify the Administrative Agent from time to time to ensure that the Administrative Agent has on record (i) an effective address, contact name, telephone number, telecopier number and electronic mail address to which notices and other communications may be sent and (ii) accurate wire instructions for such Lender.

48

(e)Reliance by Administrative Agent and Lenders.The Administrative Agent and the Lenders shall be entitled to rely and act upon any notices given by the Borrower even if such notices were not made in a manner specified herein, were incomplete or were not preceded or followed by any other form of notice specified herein. All telephonic notices to and other communications with the Administrative Agent may be recorded by the Administrative Agent, and each of the parties hereto hereby consents to such recording.

11.2Right of Set-Off.

In addition to any rights now or hereafter granted under applicable Law or otherwise, and not by way of limitation of any such rights, upon the occurrence of an Event of Default and the commencement of remedies described in Section 9.2, each Lender is authorized at any time and from time to time, without presentment, demand, protest or other notice of any kind (all of which rights being hereby expressly waived), to set-off and to appropriate and apply any and all deposits (general or special) and any other indebtedness at any time held or owing by such Lender (including, without limitation branches, agencies or Affiliates of such Lender wherever located) to or for the credit or the account of the Borrower against obligations and liabilities of the Borrower to the Lenders hereunder, under any Notes, the other Credit Documents or otherwise, irrespective of whether the Administrative Agent or the Lenders shall have made any demand hereunder and although such obligations, liabilities or claims, or any of them, may be contingent or unmatured, and any such set-off shall be deemed to have been made immediately upon the occurrence of an Event of Default even though such charge is made or entered on the books of such Lender subsequent theretoprovided, that in the event that any Defaulting Lender shall exercise any such right of setoff, (x) all amounts so set off shall be paid over immediately to the Administrative Agent for further application in accordance with the provisions of Section 2.13 and, pending such payment, shall be segregated by such Defaulting Lender from its other funds and deemed held in trust for the benefit of the Administrative Agent and the Lenders, and (y) the Defaulting Lender shall provide promptly to the Administrative Agent a statement describing in reasonable detail the Borrower Obligations owing to such Defaulting Lender as to which it exercised such right of setoff. The Borrower hereby agrees that any Participation Purchaser may exercise all rights of set-off with respect to its participation interest as fully as if such Person were a Lender hereunder.

11.3Benefit of Agreement.

(a)The provisions of this Term Loan Agreement shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns permitted hereby, except that the Borrower may not assign or otherwise transfer any of its rights or obligations hereunder without the prior written consent of each Lender and no Lender may assign or otherwise transfer any of its rights or obligations hereunder except (i) to an Eligible Assignee in accordance with the provisions of subsection (b) of this Section, (ii) by way of participation in accordance with the provisions of subsection (d) of this Section, or (iii) by way of pledge or assignment of a security interest subject to the restrictions of subsection (f) of this Section (and any other attempted assignment or transfer by any party hereto shall be null and void). Nothing in this Term Loan Agreement, expressed or implied, shall be construed to confer upon any Person (other than the Arrangers, the Administrative Agent, the parties hereto, their respective successors and assigns permitted hereby and Participation Purchasers to the extent provided in subsection (d) of this Section) any legal or equitable right, remedy or claim under or by reason of this Term Loan Agreement.

(b)Any Lender may at any time assign to one or more Eligible Assignees (subject to the consent of certain Persons as set forth in the definition thereof) all or a portion of its rights and obligations under this Term Loan Agreement (including all or a portion of its Commitment

49

and the Loans at the time owing to it); provided that (i) except in the case of an assignment of the entire remaining amount of the assigning Lender’s Commitment and the Loans at the time owing to it or in the case of an assignment to a Lender or an Affiliate of a Lender or an Approved Fund with respect to a Lender, the aggregate amount of the Commitment (which for this purpose includes Loans outstanding thereunder) subject to each such assignment, determined as of the date the Assignment and Assumption with respect to such assignment is delivered to the Administrative Agent or, if “Trade Date” is specified in the Assignment and Assumption, as of the Trade Date, shall not be less than $5,000,000 unless each of the Administrative Agent and, so long as no Event of Default has occurred and is continuing, the Borrower otherwise consents (each such consent not to be unreasonably withheld or delayed), provided, however, that the Borrower’s failure to respond within ten (10) days of receipt of written notice of such assignment shall be deemed to be Borrower’s approval thereof; (ii) each partial assignment shall be made as an assignment of a proportionate part of all the assigning Lender’s rights and obligations under this Term Loan Agreement with respect to the Loans or the Commitment assigned; and (iii) the parties to each assignment shall execute and deliver to the Administrative Agent an Assignment and Assumption, together with a processing and recordation fee of $3,500. No such assignment shall be made to any Defaulting Lender or any of its Subsidiaries, or any Person who, upon becoming a Lender hereunder, would constitute any of the foregoing persons. In connection with any assignment of rights and obligations of any Defaulting Lender hereunder, no such assignment shall be effective unless and until, in addition to the other conditions thereto set forth herein, the parties to the assignment shall make such additional payments to the Administrative Agent in an aggregate amount sufficient, upon distribution thereof as appropriate (which may be outright payment, purchases by the assignee of participations or subparticipations, or other compensating actions, including funding, with the consent of the Borrower and the Administrative Agent, the applicable pro rata share of Loans previously requested but not funded by the Defaulting Lender, to each of which the applicable assignee and assignor hereby irrevocably consent), to (x) pay and satisfy in full all payment liabilities then owed by such Defaulting Lender to the Administrative Agent or any Lender hereunder (and interest accrued thereon) and (y) acquire (and fund as appropriate) its full pro rata share of all Loans in accordance with its Commitment Percentage. Notwithstanding the foregoing, in the event that any assignment of rights and obligations of any Defaulting Lender hereunder shall become effective under applicable Law without compliance with the provisions of this paragraph, then the assignee of such interest shall be deemed to be a Defaulting Lender for all purposes of this Agreement until such compliance occurs. Subject to acceptance and recording thereof by the Administrative Agent pursuant to subsection (c) of this Section, from and after the effective date specified in each Assignment and Assumption, the Eligible Assignee thereunder shall be a party to this Term Loan Agreement and, to the extent of the interest assigned by such Assignment and Assumption, have the rights and obligations of a Lender under this Term Loan Agreement, and the assigning Lender thereunder shall, to the extent of the interest assigned by such Assignment and Assumption, be released from its obligations under this Term Loan Agreement (and, in the case of an Assignment and Assumption covering all of the assigning Lender’s rights and obligations under this Term Loan Agreement, such Lender shall cease to be a party hereto but shall continue to be entitled to the benefits of Sections 4.1 through 4.4 and 11.5 with respect to facts and circumstances occurring prior to the effective date of such assignment); provided, that except to the extent otherwise expressly agreed to by the affected parties, no assignment by a Defaulting Lender will constitute a waiver or release of any claim of any party hereunder arising from that Lender’s having been a Defaulting Lender. Upon request, the Borrower (at its expense) shall execute and deliver a Note to the assignee Lender. Any assignment or transfer by a Lender of rights or obligations under this Term Loan Agreement that does not comply with this subsection shall be treated for purposes of this Term Loan Agreement as a sale by such Lender of a participation in such rights and obligations in accordance with subsection (d) of this Section.

50

(c)The Administrative Agent, acting solely for this purpose as a non-fiduciary agent of the Borrower, shall maintain at one of its offices in the United States a copy of each Assignment and Assumption delivered to it and a register for the recordation of the names and addresses of the Lenders, and the Commitments of, and principal amounts of the Loans owing to, each Lender pursuant to the terms hereof from time to time (the “Register”). The entries in the Register shall be conclusive absent manifest error, and the Borrower, the Administrative Agent and the Lenders may treat each Person whose name is recorded in the Register pursuant to the terms hereof as a Lender hereunder for all purposes of this Term Loan Agreement, notwithstanding notice to the contrary. The Register shall be available for inspection by the Borrower and any Lender, at any reasonable time and from time to time upon reasonable prior notice.

(d)Any Lender may at any time, without the consent of, or notice to, the Borrower or the Administrative Agent, sell participations to any Person (other than a natural person or the Borrower or any of the Borrower’s Affiliates or Subsidiaries) (each, a “Participation Purchaser”) in all or a portion of such Lender’s rights and/or obligations under this Term Loan Agreement (including all or a portion of its Commitment and/or the Loans owing to it); provided that (i) such Lender’s obligations under this Term Loan Agreement shall remain unchanged, (ii) such Lender shall remain solely responsible to the other parties hereto for the performance of such obligations and (iii) the Borrower, the Administrative Agent and the other Lenders shall continue to deal solely and directly with such Lender in connection with such Lender’s rights and obligations under this Term Loan Agreement. Any agreement or instrument pursuant to which a Lender sells such a participation shall provide that such Lender shall retain the sole right to enforce this Term Loan Agreement and to approve any amendment, modification or waiver of any provision of this Term Loan Agreement; provided that such agreement or instrument may provide that such Lender will not, without the consent of the Participation Purchaser, agree to any amendment, waiver or other modification described in clauses (a) through (g) of Section 11.6 that directly affects such Participation Purchaser. Subject to subsection (e) of this Section, the Borrower agrees that each Participation Purchaser shall be entitled to the benefits of Sections 4.1 through 4.4 to the same extent as if it were a Lender and had acquired its interest by assignment pursuant to subsection (b) of this Section. To the extent permitted by law, each Participation Purchaser also shall be entitled to the benefits of Section 11.2 as though it were a Lender, provided such Participation Purchaser agrees to be subject to Section 3.8 as though it were a Lender.

(e)A Participation Purchaser shall not be entitled to receive any greater payment under Section 4.2 or 4.4 than the applicable Lender would have been entitled to receive with respect to the participation sold to such Participation Purchaser, unless the sale of the participation to such Participation Purchaser is made with the Borrower’s prior written consent. A Participation Purchaser that would be a “foreign corporation, partnership or trust” within the meaning of the Code if it were a Lender shall not be entitled to the benefits of Section 4.4 unless the Borrower is notified of the participation sold to such Participation Purchaser and such Participation Purchaser agrees, for the benefit of the Borrower, to comply with Section 4.4(d) as though it were a Lender.

(f)Any Lender may at any time pledge or assign a security interest in all or any portion of its rights under this Term Loan Agreement (including under its Notes, if any) to secure obligations of such Lender, including any pledge or assignment to secure obligations to a Federal Reserve Bank or other central banking authority; provided that no such pledge or assignment shall release such Lender from any of its obligations hereunder or substitute any such pledgee or assignee for such Lender as a party hereto.

51

(g)Notwithstanding anything to the contrary contained herein, any Lender (a “Granting Lender”) may grant to a special purpose funding vehicle managed or sponsored by the Granting Lender or an Affiliate thereof (an “SPC”) the option to fund all or any part of any Loan that such Granting Lender would otherwise be obligated to fund pursuant to this Term Loan Agreement; provided that (i) nothing herein shall constitute a commitment by any SPC to fund any Loan, (ii) if an SPC elects not to exercise such option or otherwise fails to fund all or any part of such Loan, the Granting Lender shall be obligated to fund such Loan pursuant to the terms hereof, (iii) no SPC shall have any voting rights pursuant to Section 11.6, (iv) with respect to notices, payments and other matters hereunder, the Borrower, the Administrative Agent and the Lenders shall not be obligated to deal with an SPC, but may limit their communications and other dealings relevant to such SPC to the applicable Granting Lender and (v) each Granting Lender’s obligations under this Term Loan Agreement shall remain unchanged. Each party hereto agrees that no SPC will be entitled to any rights or benefits except as expressly set forth in this subsection (g). The funding of a Loan by an SPC hereunder shall utilize the Commitment of the Granting Lender to the same extent that, and as if, such Loan were funded by such Granting Lender. Each party hereto hereby agrees that no SPC shall be liable for any indemnity or payment under this Term Loan Agreement for which a Lender would otherwise be liable for so long as, and to the extent, the Granting Lender provides such indemnity or makes such payment. Notwithstanding anything to the contrary contained in this Term Loan Agreement, any SPC may disclose on a confidential basis any non-public information relating to its funding of Loans to any rating agency, commercial paper dealer or provider of any surety or guarantee to such SPC. This subsection (g) may not be amended without the prior written consent of each Granting Lender, all or any part of whose Loan is being funded by an SPC at the time of such amendment.

(h)Notwithstanding anything to the contrary contained herein, any Lender that is a Fund may create a security interest in all or any portion of the Loans owing to it and the Notes, if any, held by it to the trustee for holders of obligations owed, or securities issued, by such Fund as security for such obligations or securities, provided that unless and until such trustee actually becomes a Lender in compliance with the other provisions of this Section 11.3, (i) no such pledge shall release the pledging Lender from any of its obligations under the Credit Documents and (ii) such trustee shall not be entitled to exercise any of the rights of a Lender under the Credit Documents even though such trustee may have acquired ownership rights with respect to the pledged interest through foreclosure or otherwise.

11.4No Waiver; Remedies Cumulative.

No failure or delay on the part of the Administrative Agent or any Lender in exercising any right, power or privilege hereunder or under any other Credit Document and no course of dealing between the Borrower and the Administrative Agent or any Lender shall operate as a waiver thereof; nor shall any single or partial exercise of any right, power or privilege hereunder or under any other Credit Document preclude any other or further exercise thereof or the exercise of any other right, power or privilege hereunder or thereunder. The rights and remedies provided herein are cumulative and not exclusive of any rights or remedies which the Administrative Agent or any Lender would otherwise have. No notice to or demand on the Borrower in any case shall entitle the Borrower to any other or further notice or demand in similar or other circumstances or constitute a waiver of the rights of the Administrative Agent or the Lenders to any other or further action in any circumstances without notice or demand.

11.5Payment of Expenses, etc.

The Borrower agrees to: (i) pay all reasonable out‑of‑pocket costs and expenses of (A) each Agent-Related Person in connection with the negotiation, preparation, execution, delivery and

52

administration of this Term Loan Agreement and the other Credit Documents and the documents and instruments referred to therein (including, without limitation, the reasonable fees and expenses of a single special counsel to the Administrative Agent) and any amendment, waiver, consent or assignment relating hereto and thereto including, but not limited to, any such amendments, waivers or consents resulting from or related to any work‑out, renegotiation or restructure relating to the performance by the Borrower under this Term Loan Agreement and (B) the Administrative Agent and the Lenders in connection with enforcement of the Credit Documents and the documents and instruments referred to therein and any reasonable expenses incurred in connection with any work‑out, renegotiation or restructure relating to the performance by the Borrower under this Term Loan Agreement (including, without limitation, in connection with any such enforcement, the reasonable fees and disbursements of counsel for the Administrative Agent and each of the Lenders) and (ii) indemnify each Agent-Related Person, each Lender and their respective Affiliates, directors, officers, employees, counsel, agents, representatives and attorneys-in-fact from and hold each of them harmless against any and all losses, liabilities, claims, damages or expenses incurred by any of them as a result of, or arising out of, or in any way related to, or by reason of, any investigation, litigation or other proceeding (whether or not any Lender is a party thereto) related to the entering into and/or performance of any Credit Document or the use of proceeds of any Loans (including other extensions of credit) hereunder or the consummation of any other transactions contemplated in any Credit Document, including, without limitation, the reasonable fees and disbursements of counsel incurred in connection with any such investigation, litigation or other proceeding; provided that the Borrower shall not be responsible for any such losses, liabilities, claims, damages or expenses to the extent incurred by reason of gross negligence or willful misconduct on the part of the Person to be indemnified, in each case as found by a final, non-appealable judgment of a court of competent jurisdiction; and provided further that in no event shall the Borrower have any liability with respect to the settlement or compromise of any claim or proceeding effected without its prior written consent (not to be unreasonably withheld or delayed) nor shall the Borrower be liable for the fees and disbursements of more than one firm of attorneys in connection with the same matter in the same jurisdiction for all Persons indemnified (provided that, in the event of a conflict of interest among such Persons indemnified by the Borrower, the Borrower will pay for additional counsel for each group of similarly situated Persons). The agreements in this Section 11.5 shall survive the repayment of the Borrower Obligations and the termination of the Commitments.

11.6Amendments, Waivers and Consents.

Neither this Term Loan Agreement nor any other Credit Document nor any of the terms hereof or thereof may be amended, changed, waived, discharged or terminated unless such amendment, change, waiver, discharge or termination is in writing and signed by the Required Lenders and the Borrower; provided that no such amendment, change, waiver, discharge or termination shall without the consent of each Lender affected thereby,

(a)extend the Maturity Date;

(b)reduce the rate or extend the time of payment of interest (other than as a result of waiving the applicability of any post-default increase in interest rates) on any Loan or reduce the amount or extend the time of payment of fees owing hereunder; provided, however, that only the consent of the Required Lenders shall be necessary to amend the definition of “Default Rate” or to waive any obligation of the Borrower to pay interest at the Default Rate;

(c)reduce or waive or extend the time of payment of the principal amount of any Loan;

53

(d)increase the Commitment of a Lender over the amount thereof in effect (it being understood and agreed that a waiver of any Default or Event of Default or a mandatory reduction in the Commitments shall not constitute a change in the terms of any Commitment of any Lender);

(e)release the Borrower from its obligations under the Credit Documents or consent to the transfer or assignment of such obligations except as permitted by Section 8.2;

(f)amend, modify or waive any provision of this Section 11.6 or Section 3.6, 3.8, 5.2, 9.1(a), 11.2, 11.3 or 11.5; or

(g)reduce any percentage specified in, or otherwise modify, the definition of Required Lenders.

Notwithstanding anything above to the contrary, unless also signed by the Administrative Agent, no amendment, waiver or consent shall affect the rights or duties of the Administrative Agent under this Agreement or any other Credit Document.

Notwithstanding the fact that the consent of all the Lenders is required in certain circumstances as set forth above, each Lender is entitled to vote as such Lender sees fit on any reorganization plan that affects the Loans and each Lender acknowledges that the provisions of Section 1126(c) of the Bankruptcy Code supersede the unanimous consent provisions set forth herein.

Notwithstanding anything to the contrary herein, no Defaulting Lender shall have any right to approve or disapprove any amendment, waiver or consent hereunder (and any amendment, waiver or consent which by its terms requires the consent of all Lenders or each affected Lender may be effected with the consent of the applicable Lenders other than Defaulting Lenders), except that (x) the Commitment of any Defaulting Lender may not be increased or extended, nor the amount owed to such Defaulting Lender reduced nor the final maturity thereof extended, without the consent of such Lender and (y) any waiver, amendment or modification requiring the consent of all Lenders or each affected Lender that by its terms affects any Defaulting Lender more adversely than other affected Lenders shall require the consent of such Defaulting Lender.

11.7Counterparts; Telecopy.

This Term Loan Agreement may be executed in any number of counterparts, each of which where so executed and delivered shall be an original, but all of which shall constitute one and the same instrument. It shall not be necessary in making proof of this Term Loan Agreement to produce or account for more than one such counterpart. Delivery of executed counterparts by telecopy shall be as effective as an original and shall constitute a representation that an original will be delivered.

11.8Headings.

The headings of the sections and subsections hereof are provided for convenience only and shall not in any way affect the meaning or construction of any provision of this Term Loan Agreement.

11.9[Reserved].

11.10Survival of Indemnification and Representations and Warranties.

54

All indemnities set forth herein and all representations and warranties made herein shall survive the execution and delivery of this Term Loan Agreement, the making of the Loans, and the repayment of the Loans and other obligations and the termination of the Commitments hereunder.

11.11Governing Law; Jurisdiction.

(a)THIS CREDIT AGREEMENT AND THE OTHER CREDIT DOCUMENTS AND THE RIGHTS AND OBLIGATIONS OF THE PARTIES HEREUNDER AND THEREUNDER SHALL BE GOVERNED BY AND CONSTRUED AND INTERPRETED IN ACCORDANCE WITH THE LAWS OF THE STATE OF NEW YORK AND THE PARTIES HERETO CONSENT TO SUCH GOVERNANCE, CONSTRUCTION AND INTERPRETATION UNDER THE LAWS OF THE STATE OF NEW YORK.

(b)EACH OF THE PARTIES HERETO IRREVOCABLY AND UNCONDITIONALLY SUBMITS TO THE JURISDICTION OF THE COURTS OF THE STATE OF NEW YORK SITTING IN NEW YORK COUNTY AND OF THE UNITED STATES DISTRICT COURT OF THE SOUTHERN DISTRICT OF NEW YORK SITTING IN NEW YORK COUNTY AND AGREES THAT ALL CLAIMS IN RESPECT OF ANY ACTION, LITIGATION OR PROCEEDING OF ANY KIND OR DESCRIPTION, WHETHER IN LAW OR EQUITY, WHETHER IN CONTRACT OR IN TORT OR OTHERWISE, AGAINST THE ADMINISTRATIVE AGENT, ANY LENDER OR ANY RELATED PARTY OF THE FOREGOING IN ANY WAY RELATING TO THIS AGREEMENT OR ANY OTHER CREDIT DOCUMENT OR THE TRANSACTIONS RELATING HERETO OR THERETO, MAY BE HEARD AND DETERMINED IN SUCH NEW YORK STATE COURT OR, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, IN SUCH FEDERAL COURT. EACH OF THE PARTIES HERETO AGREES THAT A FINAL JUDGMENT IN ANY SUCH ACTION, LITIGATION OR PROCEEDING SHALL BE CONCLUSIVE AND MAY BE ENFORCED IN OTHER JURISDICTIONS BY SUIT ON THE JUDGMENT OR IN ANY OTHER MANNER PROVIDED BY LAW. EACH PARTY HERETO IRREVOCABLY WAIVES, TO THE FULLEST EXTENT PERMITTED BY LAW, ANY OBJECTION WHICH IT MAY NOW OR HEREAFTER HAVE TO THE LAYING OF THE VENUE OF ANY SUCH PROCEEDING BROUGHT IN SUCH A COURT AND ANY CLAIM THAT ANY SUCH PROCEEDING BROUGHT IN SUCH A COURT HAS BEEN BROUGHT IN AN INCONVENIENT FORUM. NOTHING IN THIS AGREEMENT OR IN ANY OTHER CREDIT DOCUMENT SHALL AFFECT ANY RIGHT THAT ANY PARTY MAY OTHERWISE HAVE TO BRING ANY ACTION OR PROCEEDING RELATING TO THIS AGREEMENT OR ANY OTHER CREDIT DOCUMENT IN THE COURTS OF ANY JURISDICTION.

11.12Waiver of Jury Trial; Waiver of Consequential Damages.

EACH OF THE PARTIES TO THIS CREDIT AGREEMENT HEREBY IRREVOCABLY WAIVES ALL RIGHT TO TRIAL BY JURY IN ANY ACTION, PROCEEDING OR COUNTERCLAIM ARISING OUT OF OR RELATING TO THIS CREDIT AGREEMENT, ANY OF THE OTHER CREDIT DOCUMENTS OR THE TRANSACTIONS CONTEMPLATED HEREBY AND THEREBY. The Borrower agrees that the Administrative Agent, any Lender, any of their Affiliates and their respective officers, directors, employees, representatives, agents and attorneys‑in‑fact (each, an “Indemnified Party”) shall not have any liability for any indirect or consequential damages arising out of, related to or in connection with the Credit Documents except to the extent such damages were caused by reason of gross negligence or willful misconduct on the part of such Indemnified Party as finally determined by a court of competent jurisdiction.

55

11.13Time.

All references to time herein shall be references to Eastern Standard Time or Eastern Daylight time, as the case may be, unless specified otherwise.

11.14Severability.

If any provision of any of the Credit Documents is determined to be illegal, invalid or unenforceable, such provision shall be fully severable and the remaining provisions shall remain in full force and effect and shall be construed without giving effect to the illegal, invalid or unenforceable provisions. Without limiting the foregoing provisions of this Section 11.14, if and to the extent that the enforceability of any provisions in this Agreement relating to Defaulting Lenders shall be limited by Debtor Relief Laws, as determined in good faith by the Administrative Agent then such provisions shall be deemed to be in effect only to the extent not so limited.

11.15Entirety.

This Term Loan Agreement together with the other Credit Documents represent the entire agreement of the parties hereto and thereto, and supersede all prior agreements and understandings, oral or written, if any, including any commitment letters or correspondence relating to the Credit Documents or the transactions contemplated herein and therein.

11.16Confidentiality.

Each Lender agrees that it will use its reasonable best efforts to keep confidential and to cause any representative designated under Section 7.10 to keep confidential any non‑public information from time to time supplied to it under or in connection with any Credit Document including, without limitation, any such information furnished to a Lender prior to or in connection with its entry into any Credit Document (the “Information”); provided, however, that nothing herein shall affect the disclosure of any such Information to (a) the extent such Lender in good faith believes such disclosure is required by statute, rule, regulation or judicial process or applicable Law or by subpoena or similar legal process, (b) the extent requested by any regulatory authority having jurisdiction over such Lender or its Affiliates (including any self-regulatory authority, such as the National Association of Insurance Commissioners) which has been notified of the confidential nature of such Information, (c) counsel for such Lender or to its accountants, (d) bank examiners or auditors or comparable Persons, (e) any Affiliate of such Lender, (f) (i) any other Lender, (ii) any assignee, transferee or participant or any direct contractual counterparties to any swap or derivative transaction relating to Borrower and its obligations or (iii) any potential assignee, transferee or participant of all or any portion of any Lender’s rights under this Term Loan Agreement, in each case who is notified of the confidential nature of the Information and agrees to be bound by this provision or provisions reasonably comparable hereto, (g) any other Person in connection with any litigation to which any one or more of the Lenders is a party, (h) to any credit insurance provider relating to the Borrower and its obligations, (i) any agent of such Lender solely in connection with the administration of the Credit Documents, (j) on a confidential basis to (i) any rating agency in connection with rating the Borrower or its Subsidiaries or the credit facilities provided hereunder or (ii) the CUSIP Service Bureau or any similar agency in connection with the issuance and monitoring of CUSIP numbers or other market identifiers with respect to the credit facilities provided hereunder, (k) in connection with the exercise of any remedies hereunder or under any other Credit Document or any action or proceeding relating to this Term Loan Agreement or any other Credit Document or the enforcement of rights hereunder or thereunder or (l) with the consent of the Borrower; and providedfurther that no Lender shall have any obligation under this Section 11.16 to the extent any such Information becomes available on a non‑confidential basis from a source other than the Borrower or its Subsidiaries or that any Information

56

becomes publicly available other than by a breach of this Section 11.16. Each Lender agrees it will use all confidential Information exclusively for the purpose of evaluating, monitoring, selling, protecting or enforcing its Loans and other rights under the Credit Documents.

11.17Binding Effect.

(a)This Term Loan Agreement shall become effective when it shall have been executed by the Borrower, each Lender and the Administrative Agent and thereafter this Term Loan Agreement shall be binding upon and inure to the benefit of the Borrower, each Lender and the Administrative Agent, together with their respective successors and assigns. Nothing in this Term Loan Agreement, expressed or implied, shall be construed to confer upon any Person (other than the parties hereto, their successors and assigns permitted hereby and, to the extent expressly contemplated hereby, the indemnified parties hereunder) any legal or equitable right, remedy or claim under or by reason of this Term Loan Agreement.

(b)This Term Loan Agreement shall be a continuing agreement and shall remain in full force and effect until all Loans, interest, fees and other Borrower Obligations have been paid in full and all Commitments have been terminated. Upon termination, the Borrower shall have no further obligations (other than the indemnification provisions that survive) under the Credit Documents; provided that should any payment, in whole or in part, of the Borrower Obligations be rescinded or otherwise required to be restored or returned by the Administrative Agent or any Lender, whether as a result of any proceedings in bankruptcy or pursuant to court order, then the Credit Documents shall automatically be reinstated and all amounts required to be restored or returned and all costs and expenses incurred by the Administrative Agent or any Lender in connection therewith shall be deemed included as part of the Borrower Obligations.

11.18USA Patriot Act Notice.

Each Lender that is subject to the Act (as hereinafter defined) and the Administrative Agent (for itself and not on behalf of any Lender) hereby notifies the Borrower that pursuant to the requirements of the USA Patriot Act (Title III of Pub. L. 107-56 (signed into law October 26, 2001)) (the “Act”), it is required to obtain, verify and record information that identifies the Borrower, which information includes the name and address of the Borrower and other information that will allow such Lender or the Administrative Agent, as applicable, to identify the Borrower in accordance with the Act. The Borrower and each of its Subsidiaries shall provide such information and take such actions as are reasonably requested by the Administrative Agent or any Lender in order to assist the Administrative Agent and the Lenders in maintaining compliance with the Act.

11.19No Fiduciary Responsibility.

In connection with all aspects of each transaction contemplated hereby (including in connection with any amendment, waiver or other modification hereof or of any other Credit Document), the Borrower acknowledges and agrees, and acknowledges its Affiliates’ understanding, that: (i) (A) the arranging and other services regarding this Agreement provided by the Administrative Agent, the Arrangers and the Lenders are arm’s-length commercial transactions between the Borrower and its Affiliates, on the one hand, and the Administrative Agent, the other Arrangers and the Lenders on the other hand, (B) the Borrower has consulted its own legal, accounting, regulatory and tax advisors to the extent it has deemed appropriate, and (C) the Borrower is capable of evaluating, and understands and accepts, the terms, risks and conditions of the transactions contemplated hereby and by the other Credit Documents; (ii) (A) the Administrative Agent, each of the other Arrangers and each of the Lenders is and has been acting solely as a principal and, except as expressly agreed in writing by the relevant parties, has

57

not been, is not, and will not be acting as an advisor, agent or fiduciary for the Borrower or any of its respective Affiliates, or any other Person and (B) neither the Administrative Agent nor any other Arranger or Lender has any obligation to the Borrower or any of its respective Affiliates with respect to the transactions contemplated hereby except those obligations expressly set forth herein and in the other Credit Documents; and (iii) the Administrative Agent, the Arrangers, the Lenders, and their respective Affiliates may be engaged in a broad range of transactions that involve interests that differ from those of the Borrower and its respective Affiliates, and neither the Administrative Agent nor any other Arranger or any Lender has any obligation to disclose any of such interests to the Borrower and its respective Affiliates. To the fullest extent permitted by Law, the Borrower hereby waives and releases any claims that it may have against the Administrative Agent, the Arrangers and the Lenders with respect to any breach or alleged breach of agency or fiduciary duty in connection with any aspect of any transaction contemplated hereby.

11.20Acknowledgment and Consent to Bail-In of EEA Financial Institutions.

Notwithstanding anything to the contrary in any Credit Document or in any other agreement, arrangement or understanding among any such parties, each party hereto acknowledges that any liability of any Lender that is an EEA Financial Institution arising under any Credit Document, to the extent such liability is unsecured, may be subject to the write-down and conversion powers of an EEA Resolution Authority and agrees and consents to, and acknowledges and agrees to be bound by:

(a)the application of any Write-Down and Conversion Powers by an EEA Resolution Authority to any such liabilities arising hereunder which may be payable to it by any Lender that is an EEA Financial Institution; and

(b)the effects of any Bail-in Action on any such liability, including, if applicable:

(i)a reduction in full or in part or cancellation of any such liability;

(ii)a conversion of all, or a portion of, such liability into shares or other instruments of ownership in such EEA Financial Institution, its parent undertaking, or a bridge institution that may be issued to it or otherwise conferred on it, and that such shares or other instruments of ownership will be accepted by it in lieu of any rights with respect to any such liability under this Agreement or any other Credit Document; or

(iii)the variation of the terms of such liability in connection with the exercise of the write-down and conversion powers of any EEA Resolution Authority.

[the remainder of this page intentionally left blank]

58

Each of the parties hereto has caused a counterpart of this Term Loan Agreement to be duly executed and delivered as of the date first above written.

BORROWER:		MISSISSIPPI POWER COMPANY, a Mississippi Corporation
	By:	/s/Moses H. Feagin
		Moses H. Feagin Vice President, Treasurer and Chief Financial Officer

LENDERS:	BANK OF AMERICA, N.A., in its capacity as Administrative Agent
	By:	/s/Mollie S. Canup
	Name:	Mollie S. Canup
	Title:	Vice President
	BANK OF AMERICA, N.A., as a Lender
	By:	/s/William A. Merritt, III
	Name:	William A. Merritt, III
	Title:	Director

MIZUHO BANK, LTD.,
as a Lender
By:	/s/Leon Mo
Name:	Leon Mo
Title:	Authorized Signatory

BARCLAYS BANK PLC,
as a Lender
By:	/s/Marguerite Sutton
Name:	Marguerite Sutton
Title:	Vice President

CANADIAN IMPERIAL BANK OF COMMERCE, NEW YORK BRANCH, as a Lender
By:	/s/Gordon Eadon
Name:	Gordon Eadon
Title:	Authorized Signatory
By:	/s/John M. Grause
Name:	John M. Grause
Title:	Authorized Signatory

CITIBANK, N.A.,
as a Lender
By:	/s/Ashwani Khubani
Name:	Ashwani Khubani
Title:	Vice President/Director

FIFTH THIRD BANK,
as a Lender
By:	/s/Jonathan H. James
Name:	Jonathan H. James
Title:	Senior Vice President

JPMORGAN CHASE BANK, N.A.,
as a Lender
By:	/s/Peter Christensen
Name:	Peter Christensen
Title:	Vice President

PNC BANK, NATIONAL ASSOCIATION,
as a Lender
By:	/s/Daniel Scherling
Name:	Daniel Scherling
Title:	Assistant Vice President

THE BANK OF NOVA SCOTIA,
as a Lender
By:	/s/David Dewar
Name:	David Dewar
Title:	Director

COMMERZBANK AG, NEW YORK BRANCH, as a Lender
By:	/s/Barbara Stacks
Name:	Barbara Stacks
Title:	Vice President
By:	/s/Tom H.S. Kang
Name:	Tom H.S. Kang
Title:	Vice President

SUNTRUST BANK,
as a Lender
By:	/s/Hays Wood
Name:	Hays Wood
Title:	Vice President

WELLS FARGO BANK, N.A.,
as a Lender
By:	/s/Patrick Engel
Name:	Patrick Engel
Title:	Director

SCHEDULE 1.1(A)

COMMITMENT PERCENTAGES

Lenders	Closing Date Term Loan Commitment	Closing Date Term Loan Commitment Percentage	Delayed Draw Term Loan Commitment	Delayed Draw Term Loan Commitment Percentage
Bank of America, N.A.	$141,750,000.00	15.750000000%	$47,250,000.00	15.750000000%
Mizuho Bank, Ltd.	141,750,000.00	15.750000000%	47,250,000.00	15.750000000%
Barclays Bank PLC	72,000,000.00	8.000000000%	24,000,000.00	8.000000000%
Canadian Imperial Bank of Commerce, New York Branch	72,000,000.00	8.000000000%	24,000,000.00	8.000000000%
Citibank, N.A.	72,000,000.00	8.000000000%	24,000,000.00	8.000000000%
Fifth Third Bank	72,000,000.00	8.000000000%	24,000,000.00	8.000000000%
JPMorgan Chase Bank, N.A.	72,000,000.00	8.000000000%	24,000,000.00	8.000000000%
PNC Bank, National Association	72,000,000.00	8.000000000%	24,000,000.00	8.000000000%
The Bank of Nova Scotia	72,000,000.00	8.000000000%	24,000,000.00	8.000000000%
Commerzbank AG, New York Branch	37,500,000.00	4.166666667%	12,500,000.00	4.166666667%
SunTrust Bank	37,500,000.00	4.166666667%	12,500,000.00	4.166666667%
Wells Fargo Bank, N.A.	37,500,000.00	4.166666667%	12,500,000.00	4.166666667%
Totals:	$900,000,000.00	100.000000000%	$300,000,000.00	100.000000000%

SCHEDULE 1.1(B)

EXISTING TERM LOAN AGREEMENTS

Term Loan Agreement between Mississippi Power Company and Bank of America, N.A., dated as of April 9, 2015

Term Loan Agreement between Mississippi Power Company and Barclays Bank PLC, dated as of January 8, 2014, as amended by that certain First Amendment to Term Loan Agreement dated April 9, 2015

Term Loan Agreement between Mississippi Power Company and Fifth Third Bank dated March 26, 2013, as amended by that certain First Amendment to Term Loan Agreement dated April 9, 2015

Term Loan Agreement between Mississippi Power Company and Mizuho Bank, Ltd., dated as of April 10, 2015

Term Loan Agreement between Mississippi Power Company and SunTrust Bank, dated March 26, 2013, as amended by that certain First Amendment to Term Loan Agreement dated April 9, 2015

*SCHEDULE 11.1

NOTICES

To Borrower:

Mississippi Power Company

2992 West Beach

Gulfport, Mississippi 39501

Attention: Vicki Pierce

Tel: (228) 864-1211

Fax: (228) 865-5658

Email: vlpierce@southernco.com

Mississippi Power Company

30 Ivan Allen Jr. Boulevard, NW

BIN SC1407

Atlanta, Georgia 30308

Attention: Dave Symons

Tel: (404) 506-0782

Fax: (404) 506-0717

Email: dsymons@southernco.com

Website:

http://www.mississippipower.com

To Administrative Agent:

Administrative Agent’s Office

(for Payments and Requests for Credit Extensions)

Bank of America, N.A.

ONE INDEPENDENCE CENTER

101 N TRYON ST

Mail Code: NC1-001-05-46

CHARLOTTE, NC, 28255-0001

Attn: Jennifer Thayer

Telephone: 980-388-3254

Facsimile: 704-409-0486

Email: jennifer.thayer@baml.com

Remittance Instructions:

Bank of America

New York NY

ABA [            ]

Acct # [              ]

Acct Name: [                  ]

Ref: MISSISSIPPI POWER COMPANY

All Other Notices/Deliveries to Administrative Agent:

Bank of America, N.A.

Agency Management

NC1-026-06-03

900 West Trade St, 6^th Floor

Charlotte, NC 28255

Attn: Mollie S. Canup

Telephone: (980) 387-5449

Facsimile: (704) 409-0011

Email: mollie.s.canup@baml.com

EXHIBIT 2.4

FORM OF NOTICE OF BORROWING OF TERM LOAN

TO:	Bank of America, N.A., as Administrative Agent
RE:	Term Loan Agreement dated as of March 8, 2016 among Mississippi Power Company (the "Borrower"), the Lenders named therein and Bank of America, N.A., as Administrative Agent (as the same may be amended, modified, extended or restated from time to time, the "Term Loan Agreement")
DATE:	____________, 20__

______________________________________________________________________________

1. This Notice of Borrowing is made pursuant to the terms of the Term Loan Agreement. All capitalized terms used herein unless otherwise defined shall have the meanings set forth in the Term Loan Agreement.

2. Please be advised that the Borrower is requesting [Closing Date Term Loans][Delayed Draw Term Loans] in the amount of $__________ to be funded on ____________, 20__ at the interest rate option set forth in paragraph 3 below.

x. Subsequent to the funding of the requested [Closing Date Term Loans] [Delayed Draw Term Loans], the aggregate amount of [Closing Date Term Loans] [Delayed Draw Term Loans] outstanding will be $_____________ which is less than or equal to the [Closing Date Term Loan] [Delayed Draw Term Loan] Commitment.

3. The interest rate option applicable to the requested [Closing Date Term Loans][Delayed Draw Term Loans] shall be:

a.________the Adjusted Base Rate

b.________the Adjusted Eurodollar Rate for an Interest Period of:

________ one month

________ two months

________ three months

________ six months

4. Unless notification to the contrary is received by the Administrative Agent prior to the date on which funds are to be advanced, as of the date on which funds are to be advanced, all representations and warranties required to be made pursuant to the Term Loan Agreement and the other Credit Documents will be true and correct in all material respects.

5. Unless notification to the contrary is received by the Administrative Agent prior to the date on which funds are to be advanced, as of the date on which funds are to be advanced, no Default or Event of Default will have occurred and be continuing or will be caused by this Notice of Borrowing.

6. Please credit the following account with the [Closing Date Term Loans][Delayed Draw Term Loans] requested pursuant to this Notice of Borrowing:

Bank: [                               ]

[                           ]

ABA #:  [                   ]

Acct #: [                ]

Account Name: [                            ]

MISSISSIPPI POWER COMPANY,

a Mississippi corporation

By: __________________________________

Name: _______________________________

Title:  ________________________________

EXHIBIT 2.6

FORM OF NOTICE OF CONTINUATION/CONVERSION

TO:	Bank of America, N.A., as Administrative Agent
RE:	Term Loan Agreement dated as of March 8, 2016 among Mississippi Power Company (the "Borrower"), the Lenders named therein and Bank of America, N.A., as Administrative Agent (as the same may be amended, modified, extended or restated from time to time, the "Term Loan Agreement")
DATE:	____________, 20__

______________________________________________________________________________

1. This Notice of Continuation/Conversion is made pursuant to the terms of the Term Loan Agreement. All capitalized terms used herein unless otherwise defined shall have the meanings set forth in the Term Loan Agreement.

2. Please be advised that the Borrower is requesting that a portion of the current outstanding [Closing Date Term Loans][Delayed Draw Term Loans] in the amount of $__________ currently accruing interest at ________ be continued or converted as of ___________, 20__ at the interest rate option set forth in paragraph 3 below.

3. The interest rate option applicable to the continuation or conversion of all or part of the existing [Closing Date Term Loans][Delayed Draw Term Loans] (as set forth above) shall be:

a._______the Adjusted Base Rate

b._______the Adjusted Eurodollar Rate for an Interest Period of:

________ one month

________ two months

________ three months

________ six months

4. Unless notification to the contrary is received by the Administrative Agent prior to the date on which [Closing Date Term Loans][Delayed Draw Term Loans] are to be continued or converted, as of the date on which [Closing Date Term Loans][Delayed Draw Term Loans] are to be continued or converted, all representations and warranties required to be made pursuant to the Term Loan Agreement and the other Credit Documents will be true and correct in all material respects.

5. Unless notification to the contrary is received by the Administrative Agent prior to the date on which [Closing Date Term Loans][Delayed Draw Term Loans] are to be continued or converted, as of the date on which [Closing Date Term Loans][Delayed Draw Term Loans] are to be continued or converted, no Default or Event of Default will have occurred and be continuing or will be caused by this Notice of Continuation/Conversion.

MISSISSIPPI POWER COMPANY,

a Mississippi corporation

By: __________________________________

Name: _______________________________

Title:  ________________________________

EXHIBIT 2.9(a)

FORM OF

CLOSING DATE TERM LOAN NOTE

___________, 20__

FOR VALUE RECEIVED, MISSISSIPPI POWER COMPANY, a Mississippi corporation (the "Borrower"), hereby promises to pay to the order of ____________________ (the "Lender"), at the Administrative Agent’s Office as set forth in that certain Term Loan Agreement dated as of March 8, 2016 among the Borrower, the Lenders named therein (including the Lender) and Bank of America, N.A., as Administrative Agent (as the same may be amended, modified, extended or restated from time to time, the "Term Loan Agreement") (or at such other place or places as the holder of this Closing Date Term Loan Note may designate), the aggregate amount of all advances made by the Lender as Closing Date Term Loans pursuant to the Lender’s Closing Date Term Loan Commitment (and not otherwise repaid), in lawful money and in immediately available funds, on the dates and in the principal amounts provided in the Term Loan Agreement, and to pay interest on the unpaid principal amount of each Closing Date Term Loan made by the Lender, at such office, in like money and funds, for the period commencing on the date of each Closing Date Term Loan until each Closing Date Term Loan shall be paid in full, at the rates per annum and on the dates provided in the Term Loan Agreement.

This Note is one of the Closing Date Term Loan Notes referred to in the Term Loan Agreement and evidences Closing Date Term Loans made by the Lender thereunder. The Lender shall be entitled to the benefits of the Term Loan Agreement. Capitalized terms used in this Closing Date Term Loan Note have the respective meanings assigned to them in the Term Loan Agreement and the terms and conditions of the Term Loan Agreement are expressly incorporated herein and made a part hereof.

The Term Loan Agreement provides for the acceleration of the maturity of the Closing Date Term Loans evidenced by this Closing Date Term Loan Note upon the occurrence of certain events (and for payment of collection costs in connection therewith) and for prepayments of Closing Date Term Loans upon the terms and conditions specified therein. In the event this Closing Date Term Loan Note is not paid when due at any stated or accelerated maturity, the Borrower agrees to pay, in addition to the principal and interest, all costs of collection, including reasonable attorney fees.

Except as permitted by Section 11.3(b) of the Term Loan Agreement, this Closing Date Term Loan Note may not be assigned by the Lender to any other Person.

THIS CLOSING DATE TERM LOAN NOTE SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK.

IN WITNESS WHEREOF, the Borrower has caused this Closing Date Term Loan Note to be executed as of the date first above written.

MISSISSIPPI POWER COMPANY,

a Mississippi corporation

By: __________________________________

Name: _______________________________

Title:  ________________________________

EXHIBIT 2.9(b)

FORM OF

DELAYED DRAW TERM LOAN NOTE

___________, 20__

FOR VALUE RECEIVED, MISSISSIPPI POWER COMPANY, a Mississippi corporation (the "Borrower"), hereby promises to pay to the order of ____________________ (the "Lender"), at the Administrative Agent’s Office as set forth in that certain Term Loan Agreement dated as of March 8, 2016 among the Borrower, the Lenders named therein (including the Lender) and Bank of America, N.A., as Administrative Agent (as the same may be amended, modified, extended or restated from time to time, the "Term Loan Agreement") (or at such other place or places as the holder of this Delayed Draw Term Loan Note may designate), the aggregate amount of all advances made by the Lender as Delayed Draw Term Loans pursuant to the Lender’s Delayed Draw Term Loan Commitment (and not otherwise repaid), in lawful money and in immediately available funds, on the dates and in the principal amounts provided in the Term Loan Agreement, and to pay interest on the unpaid principal amount of each Delayed Draw Term Loan made by the Lender, at such office, in like money and funds, for the period commencing on the date of each Delayed Draw Term Loan until each Delayed Draw Term Loan shall be paid in full, at the rates per annum and on the dates provided in the Term Loan Agreement.

This Note is one of the Delayed Draw Term Loan Notes referred to in the Term Loan Agreement and evidences Delayed Draw Term Loans made by the Lender thereunder. The Lender shall be entitled to the benefits of the Term Loan Agreement. Capitalized terms used in this Delayed Draw Term Loan Note have the respective meanings assigned to them in the Term Loan Agreement and the terms and conditions of the Term Loan Agreement are expressly incorporated herein and made a part hereof.

The Term Loan Agreement provides for the acceleration of the maturity of the Delayed Draw Term Loans evidenced by this Delayed Draw Term Loan Note upon the occurrence of certain events (and for payment of collection costs in connection therewith) and for prepayments of Delayed Draw Term Loans upon the terms and conditions specified therein. In the event this Delayed Draw Term Loan Note is not paid when due at any stated or accelerated maturity, the Borrower agrees to pay, in addition to the principal and interest, all costs of collection, including reasonable attorney fees.

Except as permitted by Section 11.3(b) of the Term Loan Agreement, this Delayed Draw Term Loan Note may not be assigned by the Lender to any other Person.

THIS DELAYED DRAW TERM LOAN NOTE SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK.

IN WITNESS WHEREOF, the Borrower has caused this Delayed Draw Term Loan Note to be executed as of the date first above written.

MISSISSIPPI POWER COMPANY,

a Mississippi corporation

By: __________________________________

Name: _______________________________

Title:  ________________________________

EXHIBIT 7.1(c)

FORM OF COMPLIANCE CERTIFICATE

TO:	Bank of America, N.A., as Administrative Agent
RE:	Term Loan Agreement dated as of March 8, 2016 among Mississippi Power Company (the "Borrower"), the Lenders named therein and Bank of America, N.A., as Administrative Agent (as the same may be amended, modified, extended or restated from time to time, the "Term Loan Agreement")
DATE:	____________, 20__

______________________________________________________________________________

Pursuant to the terms of the Term Loan Agreement, I, __________________, [Chief Financial Officer/ Treasurer/ Assistant Treasurer] of Mississippi Power Company, hereby certify that, as of the fiscal quarter ending __________, 20__, the statements and calculations below are accurate and complete in all respects (all capitalized terms used below shall have the meanings set forth in the Term Loan Agreement):

1.Compliance with Section 7.11:

x.Ratio of Indebtedness to Capitalization

a.	Indebtedness		$___________________
b.	Capitalization		$___________________
c.	Ratio of Indebtedness to Capitalization		________ : ________
Maximum Allowed:		.65 : 1.0.

2.No Default or Event of Default exists except as indicated on a separate page attached hereto, together with an explanation of the action taken or proposed to be taken by the Borrower with respect thereto.

MISSISSIPPI POWER COMPANY,

a Mississippi corporation

By: __________________________________

Name: _______________________________

Title:  ________________________________

EXHIBIT 11.3(b)

FORM OF

ASSIGNMENT AND ASSUMPTION

This Assignment and Assumption (the "Assignment and Assumption") is dated as of the Effective Date set forth below and is entered into by and between [Insert name of Assignor] (the "Assignor") and [Insert name of Assignee] (the "Assignee"). Capitalized terms used but not defined herein shall have the meanings given to them in the Term Loan Agreement identified below (as amended, the "Term Loan Agreement"), receipt of a copy of which is hereby acknowledged by the Assignee. The Standard Terms and Conditions set forth in Annex 1 attached hereto are hereby agreed to and incorporated herein by reference and made a part of this Assignment and Assumption as if set forth herein in full.

For an agreed consideration, the Assignor hereby irrevocably sells and assigns to the Assignee, and the Assignee hereby irrevocably purchases and assumes from the Assignor, subject to and in accordance with the Standard Terms and Conditions and the Term Loan Agreement, as of the Effective Date inserted by the Administrative Agent as contemplated below (i) all of the Assignor's rights and obligations in its capacity as a Lender under the Term Loan Agreement and any other documents or instruments delivered pursuant thereto to the extent related to the amount and percentage interest identified below of all of such outstanding rights and obligations of the Assignor under the respective facilities identified below and (ii) to the extent permitted to be assigned under applicable law, all claims, suits, causes of action and any other right of the Assignor (in its capacity as a Lender) against any Person, whether known or unknown, arising under or in connection with the Term Loan Agreement, any other documents or instruments delivered pursuant thereto or the loan transactions governed thereby or in any way based on or related to any of the foregoing, including, but not limited to, contract claims, tort claims, malpractice claims, statutory claims and all other claims at law or in equity related to the rights and obligations sold and assigned pursuant to clause (i) above (the rights and obligations sold and assigned pursuant to clauses (i) and (ii) above being referred to herein collectively as, the "Assigned Interest"). Such sale and assignment is without recourse to the Assignor and, except as expressly provided in this Assignment and Assumption, without representation or warranty by the Assignor.

1.	Assignor:	___________________________________
2.	Assignee:	___________________________________ [which is an Affiliate/Approved Fund of [identify Lender]1]
3.	Borrower	Mississippi Power Company
4.	Administrative Agent:	Bank of America, N.A., as the administrative agent under the Term Loan Agreement
5.	Term Loan Agreement	Term Loan Agreement dated as of March 8, 2016 among Mississippi Power Company (the "Borrower"), the Lenders named therein and Bank of America, N.A., as Administrative Agent (as amended, modified, extended or restated from time to time)

________________________

¹ Select as applicable

6. Assigned Interest:

Facility Assigned	Aggregate Amount of [Closing Date Term Loan][Delayed Draw Term Loan] Commitment/Term Loans for all Lenders*	Amount of [Closing Date Term Loan][Delayed Draw Term Loan] Commitment/Term Loans Assigned*	Percentage Assigned of Commitment/ Term Loans2
	$	$	%

[7.Trade Date:______________]³ 

Effective Date: _____________ ___, 20___ [TO BE INSERTED BY ADMINISTRATIVE AGENT AND WHICH SHALL BE THE EFFECTIVE DATE OF RECORDATION OF TRANSFER IN THE REGISTER THEREFOR.]

The terms set forth in this Assignment and Assumption are hereby agreed to:

ASSIGNOR

[NAME OF ASSIGNOR]

By: ___________________________________

Name: ___________________________________

Title: ___________________________________

ASSIGNEE

[NAME OF ASSIGNEE]

By: ___________________________________

Name: ___________________________________

Title: ___________________________________

_________________________________

^*Amount to be adjusted by the counterparties to take into account any payments or prepayments made between the Trade Date and the Effective Date.

²Set forth, to at least 9 decimals, as a percentage of the Commitment/Loans of all Lenders thereunder.

³To be completed if the Assignor and the Assignee intend that the minimum assignment amount is to be determined as of the Trade Date.

Consented to and Accepted:

BANK OF AMERICA, N.A., as

Administrative Agent

By: ___________________________________

Name: ___________________________________

Title: ___________________________________

Consented to and Accepted:

MISSISSIPPI POWER COMPANY, as Borrower

By: ___________________________________

Name: ___________________________________

Title: ___________________________________

ANNEX 1

STANDARD TERMS AND CONDITIONS FOR

ASSIGNMENT AND ASSUMPTION

1. Representations and Warranties.

1.1 Assignor. The Assignor (a) represents and warrants that (i) it is the legal and beneficial owner of the Assigned Interest, (ii) the Assigned Interest is free and clear of any lien, encumbrance or other adverse claim and (iii) it has full power and authority, and has taken all action necessary, to execute and deliver this Assignment and Assumption and to consummate the transactions contemplated hereby; and (b) assumes no responsibility with respect to (i) any statements, warranties or representations made in or in connection with the Term Loan Agreement or any other Credit Document, (ii) the execution, legality, validity, enforceability, genuineness, sufficiency or value of the Credit Documents or any collateral thereunder, (iii) the financial condition of the Borrower, any of its Subsidiaries or Affiliates or any other Person obligated in respect of any Credit Document or (iv) the performance or observance by the Borrower, any of its Subsidiaries or Affiliates or any other Person of any of their respective obligations under any Credit Document.

1.2. Assignee. The Assignee (a) represents and warrants that (i) it has full power and authority, and has taken all action necessary, to execute and deliver this Assignment and Assumption and to consummate the transactions contemplated hereby and to become a Lender under the Term Loan Agreement, (ii) it meets all requirements of an Eligible Assignee under the Term Loan Agreement (subject to receipt of such consents as may be required under the Term Loan Agreement), (iii) from and after the Effective Date, it shall be bound by the provisions of the Term Loan Agreement as a Lender thereunder and, to the extent of the Assigned Interest, shall have the obligations of a Lender thereunder, (iv) it is sophisticated with respect to decisions to acquire assets of the type represented by the Assigned Interest and either it, or the Person exercising discretion in making its decision to acquire the Assigned Interest, is experienced in acquiring assets of such type, (v) it has received a copy of the Term Loan Agreement, together with copies of the most recent financial statements delivered pursuant to Section 7.1 thereof, as applicable, and such other documents and information as it has deemed appropriate to make its own credit analysis and decision to enter into this Assignment and Assumption and to purchase the Assigned Interest on the basis of which it has made such analysis and decision independently and without reliance on the Administrative Agent or any other Lender, (vi) it has, independently and without reliance upon the Administrative Agent or any other Lender and based on such documents and information as it has deemed appropriate, made its own credit analysis and decision to enter into this Assignment and Assumption and to purchase the Assigned Interest, (vii) if it is a Lender that is not a "United States person" (as such term is defined in Section 7701(a)(30) of the Code), attached hereto is any documentation required to be delivered by it pursuant to the terms of the Term Loan Agreement, duly completed and executed by the Assignee and (viii) if it is a Lender that is a “United States person” (as such term is defined in Section 7701(a)(30) of the Code), attached hereto is an Internal Revenue Service Form W-9 as required to be delivered by it pursuant to the terms of the Term Loan Agreement, duly completed and executed by the Assignee; and (b) agrees that (i) it will, independently and without reliance on the Administrative Agent, the Assignor or any other Lender, and based on such documents and information as it shall deem appropriate at the time, continue to make its own credit decisions in taking or not taking action under the Credit Documents, and (ii) it will perform in accordance with their terms all of the obligations which by the terms of the Credit Documents are required to be performed by it as a Lender.

2. Payments. From and after the Effective Date, the Administrative Agent shall make all payments in respect of the Assigned Interest (including payments of principal, interest, fees and other amounts) to the Assignor for amounts which have accrued to but excluding the Effective Date and to the Assignee for amounts which have accrued from and after the Effective Date.

3. General Provisions. This Assignment and Assumption shall be binding upon, and inure to the benefit of, the parties hereto and their respective successors and assigns. This Assignment and Assumption may be executed in any number of counterparts, which together shall constitute one instrument. Delivery of an executed counterpart of a signature page of this Assignment and Assumption by telecopy shall be effective as delivery of a manually executed counterpart of this Assignment and Assumption. This Assignment and Assumption shall be governed by, and construed in accordance with, the law of the State of New York.

___________________________________

EX-10.E1

Exhibit 10(e)1

December 11, 2014

Mr. Chip Troxclair

1630 Westshore Drive

Houston, Texas 77094

Dear Chip:

We are pleased to extend you a conditional offer of employment for the position of Vice President - Kemper Development. You will be an officer of Mississippi Power Company and report directly to Ed Holland, and your expected start date will be January 2, 2015.

The terms and conditions of your employment are as follows:

• An annual base salary of $600,000 to be paid on a bi-weekly basis in accordance with the Company's normal payroll practices.

• Participation in the Company's annual variable pay plan; the Performance Pay Program (PPP). Your Target Award under this plan is 100% of annual base salary. The actual amount of any award you may receive can range from 0-200% of target based upon company, business unit and individual performance.

• A signing bonus of $275,000 payable within 30 days from date of hire.

• Payment of all reasonable travel and commuting expenses related to the Kemper Project, including use of System Air for commuting between Houston/Charlotte and Meridian. As appropriate, such expense repayments will be grossed-up where subject to personal income tax.

• Participation in the capital accumulation plans sponsored by the Company for similarly situated employees including the Southern Company Employee Savings Plan, the Southern Company Supplemental Benefit Plan and the Southern Company Deferred Compensation Plan pursuant to the terms and eligibility requirement of those plans.

• You will receive paid holidays (10 per year) and 20 days (160 hours) of vacation.

• Safe and effective completion bonus as described in Attachment 1.

Southern Company strictly prohibits its employees from using or disseminating any confidential information of a prior employer and related materials while employed by Southern Company. We are hereby advising you that Southern Company does not want such confidential information nor does Southern Company want you to utilize such information while employed at Southern Company. By signing this letter, you agree that to the extent that you have any confidential information from any previous employer or any of its affiliated companies, you will not use, disclose or disseminate that confidential information, directly or indirectly, while employed by Southern Company. You further agree that all confidential records, documents, and similar items of your former employer shall not be utilized while employed with Southern Company

This offer is contingent upon you successfully meeting Southern Company's employment requirements which include, but are not limited to, verification of your application, a satisfactory background investigation and drug screen. We will contact you to confirm your start date after these employment requirements have been completed.

Your medical coverage begins on your first day of employment. You will receive information from our Employee Service Center within 10 days of your start date that provides directions on enrolling for your benefits coverages. In the interim, if you need medical attention, you will be covered under a basic benefit plan which consists of medical, long-term disability, and non-contributory life insurance.

We look forward to having you as part of our team! If you have any questions, please don't hesitate to contact me.

Sincerely,

/s/G. Edison Holland

SOUTHERN COMPANY

ATTACHMENT 1

For purposes of this letter agreement, it is agreed that the Executive's entitlement to all or part of the target bonus for safe and effective completion of the Kemper Project (as defined below) will include the following considerations, as determined in the sole discretion of the chief executive officer ("CEO") of Mississippi Power Company (the "Company").

• Adherence to all policies, procedures, regulation and laws of and applicable to the Company, including without limitation:

—   Ethical and Legal Compliance Expectations

—   Equal Employment/ Harassment

—   Workplace Threats and Violence

—   Electronic Communications

—   Safety and the Environment

—   Drugs and Alcohol

—   Conflict of Interest

• Consistent commitment to the Company's standards of personal and workplace safety, process safety management and ethical conduct, as exhibited through tone from the top communications and behaviors, and effective execution of related policies and practices

•"Completion" of the Kemper Project shall occur when Kemper IGCC is placed in service.

The following schedule reflects the target bonus payable to Executive upon authorization of the CEO following Completion of the Kemper Project as of the listed dates:

On or before October 31, 2015	up to $1,000,000
On or before November 30, 2015	up to  $900,000
On or before December 31, 2015	up to   $800,000
On or before January 31, 2016	up to   $700,000
On or before February 29, 2016	up to   $600,000
On or before March 31,2016	up to   $500,000

Any bonus payment authorized by the CEO shall be paid no later than thirty (30) days following Completion of the Kemper Project.

EX-10.E2

Exhibit 10(e)2

PERFORMANCE AWARD AGREEMENT

THISPERFORMANCE AWARD AGREEMENT (the "Agreement"), made and entered into by and between Southern Company Services, Inc. (the "Company") and Emile J. Troxclair III ("Employee"), shall be effective as of January 3, 2015 (the "Effective Date").

WITNESSETH:

WHEREAS, Employee is Senior Vice President for the Company and his services are critical to the successful safe and effective completion of the Integrated Coal Gasification Combined Cycle facility in Kemper County, Mississippi (the “Project”);

WHEREAS, the Company desires to provide an opportunity for Employee to earn a performance-based award upon the successful completion of the Project on or before March 31, 2016 under the following terms;

NOW, THEREFORE, in consideration of the premises, and the agreement of the parties set forth in the Agreement, and other good and valuable consideration, the receipt and sufficiency of which are acknowledged, the parties agree as follows:

1.     Performance Award Amount. If Employee remains actively employed in his position as of the Effective Date in support of the Project through the date the Project is placed in service (“Project Completion Date”), Employee shall become vested in the following amount provided the applicable Performance Conditions set forth in Section 2 below are met:

Performance Award Amount	Project Completion Date
Up to $1,000,000	On or before October 31, 2015
Up to $900,000	On or before November 30, 2105
Up to $800,000	On or before December 31, 2015
Up to $700,000	On or before January 31, 2016
Up to $600,000	On or before February 29, 2016
Up to $500,000	On or before March 31, 2016

The Performance Awards under this Paragraph 1 shall be treated as awards of Cash-Based Awards under the Southern Company Omnibus Incentive Compensation Plan (the "Omnibus Plan") and therefore, governed by the terms of that plan.

2.    Performance Conditions. The following performance conditions shall be applicable to the Award Amounts set forth above:

1

(a) In addition to completion by the applicable Performance Completion Date, entitlement to the applicable Cash-Based Award Amount shall be based on the safe and effective completion of the Project and will include the following considerations:

(i) Adherence to all policies, procedures, regulation and laws of and applicable to the Company, including without limitation:

• Ethical and Legal Compliance Expectations

• Equal Employment / Harassment

• Workplace Threats and Violence

• Electronic Communications

• Safety and the Environment

• Drugs and Alcohol

• Conflict of Interest

(ii) Consistent commitment to the Company’s standards of personal and workplace safety, process safety management and ethical conduct, as exhibited through tone from the top communications and behaviors, and effective execution of related policies and practices.

(b) Determination of the degree of satisfaction of the Performance Conditions, including a determination of the Project Completion Date, shall be made solely by the Chief Executive Officer of Mississippi Power Company (“CEO”). The determination of the degree of satisfaction of the Performance Conditions shall be made within thirty (30) days following the Project Completion Date. The date the determination is made is referred to as the “Determination Date.”

3.    Vesting and Payment of Performance Award.

(a) Generally. If the CEO determines that the Performance Conditions have been met fully or in part, the Performance Award Amount shall be determined by the CEO and such amount shall vest on the Determination Date. Unless modified by the provisions set forth in Paragraphs 3(b) or 3(c), the vested Performance Award, or any portion thereof that has not been deferred as provided in Section 3(c), shall be paid in cash to Employee in a lump sum within 45 days following vesting (the "Scheduled Payment Date").

(b) Death. If Employee dies after the Performance Award has vested and prior to the Scheduled Payment Date, the applicable award amount, except any amount deferred under Section 3(c), shall be paid to Employee’s estate.

(c) Deferral of Payout. Employee may elect to defer payout of any portion of the vested Performance Award into the Southern Company Deferred Compensation Plan (the “DCP”) so long as such deferral does not violate either the provisions of Section 409A of the Internal Revenue Code or the terms of the DCP, including provisions in

2

the DCP concerning the timing and form of elections. A vested Performance Award hereunder shall be considered an “Incentive Award” under the terms of the DCP.

4.    Amendment and/or Termination of the Agreement. The Agreement terminates when all amounts have been paid or forfeited pursuant to Section 3. Notwithstanding the preceding sentence, the Employee and the Company may mutually agree to amend or terminate the Agreement prior to the end of the term only by written agreement signed by each party.

5.    Confidentiality. Employee represents and agrees that he will keep all terms and provisions of the Agreement completely confidential, except for possible disclosures to his legal and financial advisors and his spouse or to the extent required by law, and Employee further agrees that he will not disclose the terms, provisions or information contained in or concerning the Agreement to anyone other than those persons named above, including, but not limited to, any past, present or prospective employee or applicant for employment with the Company or any affiliate of the Company. The Agreement is not intended in any way to proscribe Employee's right and ability to provide information to any federal, state or local government in the lawful exercise of such governments' governmental functions.     

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

7.    Unsecured General Creditor. The Company shall neither reserve nor specifically set aside funds for the payment of its obligations under the Agreement, and such obligations shall be paid solely from the general assets of the Company. Notwithstanding that Employee may be entitled to receive payments under the terms and conditions of the Agreement, the assets from which such amounts may be paid shall at all times be subject to the claims of the Company's creditors.

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

9.    Compensation. Any compensation paid to Employee pursuant to the Agreement shall not be considered "compensation" as the term is defined in The Southern Company Employee Savings Plan, or "earnings" as such term is defined in The Southern Company Pension Plan. Except as provided in Section 3(c), a Performance Award paid to Employee shall not be considered wages, salaries or compensation under any other Company-sponsored employee benefit or compensation plan or program, unless the explicit terms of such plan or program provides otherwise.

3

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

11.    Governing Law. The Agreement, and all rights under it, shall be governed by and construed in accordance with the laws of the State of Mississippi, without giving effect to principles of conflicts of laws.

IN WITNESS WHEREOF, the Agreement has been executed by the parties above, this 18th day of December 2014.

COMPANY
/s/G. Edison Holland Jr.
By:	G. Edison Holland Jr.
Its:	President and CEO
EMPLOYEE
/s/Emile J. Troxclair
Emile J. Troxclair

4

EX-31.A1

Exhibit 31(a)1

THE SOUTHERN COMPANY

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, Thomas A. Fanning, certify that:

1. I have reviewed this quarterly report on Form 10-Q of The Southern Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  May 5, 2016

/s/Thomas A. Fanning

Thomas A. Fanning

Chairman, President and

Chief Executive Officer

EX-31.A2

Exhibit 31(a)2

THE SOUTHERN COMPANY

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, Art P. Beattie, certify that:

1. I have reviewed this quarterly report on Form 10-Q of The Southern Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  May 5, 2016

/s/Art P. Beattie

Art P. Beattie

Executive Vice President and Chief Financial Officer

EX-31.B1

Exhibit 31(b)1

ALABAMA POWER COMPANY

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, Mark A. Crosswhite, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Alabama Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  May 5, 2016

/s/Mark A. Crosswhite

Mark A. Crosswhite

Chairman, President and Chief Executive Officer

EX-31.B2

Exhibit 31(b)2

ALABAMA POWER COMPANY

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, Philip C. Raymond, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Alabama Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  May 5, 2016

/s/Philip C. Raymond

Philip C. Raymond

Executive Vice President, Chief Financial Officer

and Treasurer

EX-31.C1

Exhibit 31(c)1

GEORGIA POWER COMPANY

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, W. Paul Bowers, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Georgia Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:   May 5, 2016

/s/W. Paul Bowers

W. Paul Bowers

Chairman, President and Chief Executive Officer

EX-31.C2

Exhibit 31(c)2

GEORGIA POWER COMPANY

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, W. Ron Hinson, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Georgia Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  May 5, 2016

/s/W. Ron Hinson

W. Ron Hinson

Executive Vice President, Chief Financial Officer, Treasurer and Corporate Secretary

EX-31.D1

Exhibit 31(d)1

GULF POWER COMPANY

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, S. W. Connally, Jr., certify that:

1. I have reviewed this quarterly report on Form 10-Q of Gulf Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  May 5, 2016

/s/S. W. Connally, Jr.

S. W. Connally, Jr.

Chairman, President and Chief Executive Officer

EX-31.D2

Exhibit 31(d)2

GULF POWER COMPANY

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, Xia Liu, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Gulf Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  May 5, 2016

/s/Xia Liu

Xia Liu

Vice President and Chief Financial Officer

EX-31.E1

Exhibit 31(e)1

MISSISSIPPI POWER COMPANY

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, Anthony L. Wilson, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Mississippi Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  May 5, 2016

/s/Anthony L. Wilson

Anthony L. Wilson

President and

 Chief Executive Officer

EX-31.E2

Exhibit 31(e)2

MISSISSIPPI POWER COMPANY

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, Moses H. Feagin, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Mississippi Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  May 5, 2016

/s/Moses H. Feagin

Moses H. Feagin

Vice President, Treasurer and

Chief Financial Officer

EX-31.F1

Exhibit 31(f)1

SOUTHERN POWER COMPANY

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, Joseph A. Miller, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Southern Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:   May 5, 2016

/s/Joseph A. Miller

Joseph A. Miller

President and Chief Executive Officer

EX-31.F2

Exhibit 31(f)2

SOUTHERN POWER COMPANY

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, William C. Grantham, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Southern Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  May 5, 2016

/s/William C. Grantham

William C. Grantham

Vice President, Treasurer and Chief

Financial Officer

EX-32.A

Exhibit 32(a)

CERTIFICATION

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the accompanying Quarterly Report on Form 10-Q of The Southern Company for the quarter ended March 31, 2016, we, the undersigned, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of our individual knowledge and belief, that:

(1) such Quarterly Report on Form 10-Q of The Southern Company for the quarter ended March 31, 2016, which this statement accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in such Quarterly Report on Form 10-Q of The Southern Company for the quarter ended March 31, 2016, fairly presents, in all material respects, the financial condition and results of operations of The Southern Company.

/s/Thomas A. Fanning

Thomas A. Fanning

Chairman, President and

Chief Executive Officer

/s/Art P. Beattie

Art P. Beattie

Executive Vice President and

Chief Financial Officer

May 5, 2016

EX-32.B

Exhibit 32(b)

CERTIFICATION

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the accompanying Quarterly Report on Form 10-Q of Alabama Power Company for the quarter ended March 31, 2016, we, the undersigned, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of our individual knowledge and belief, that:

(1) such Quarterly Report on Form 10-Q of Alabama Power Company for the quarter ended March 31, 2016, which this statement accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in such Quarterly Report on Form 10-Q of Alabama Power Company for the quarter ended March 31, 2016, fairly presents, in all material respects, the financial condition and results of operations of Alabama Power Company.

/s/Mark A. Crosswhite

Mark A. Crosswhite

Chairman, President and Chief Executive Officer

/s/Philip C. Raymond

Philip C. Raymond

Executive Vice President,

Chief Financial Officer and Treasurer

May 5, 2016

EX-32.C

Exhibit 32(c)

CERTIFICATION

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the accompanying Quarterly Report on Form 10-Q of Georgia Power Company for the quarter ended March 31, 2016, we, the undersigned, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of our individual knowledge and belief, that:

(1) such Quarterly Report on Form 10-Q of Georgia Power Company for the quarter ended March 31, 2016, which this statement accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in such Quarterly Report on Form 10-Q of Georgia Power Company for the quarter ended March 31, 2016, fairly presents, in all material respects, the financial condition and results of operations of Georgia Power Company.

/s/W. Paul Bowers

W. Paul Bowers

Chairman, President and Chief Executive Officer

/s/W. Ron Hinson

W. Ron Hinson

Executive Vice President, Chief Financial Officer, Treasurer and Corporate Secretary

May 5, 2016

EX-32.D

Exhibit 32(d)

CERTIFICATION

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the accompanying Quarterly Report on Form 10-Q of Gulf Power Company for the quarter ended March 31, 2016, we, the undersigned, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of our individual knowledge and belief, that:

(1) such Quarterly Report on Form 10-Q of Gulf Power Company for the quarter ended March 31, 2016, which this statement accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in such Quarterly Report on Form 10-Q of Gulf Power Company for the quarter ended March 31, 2016, fairly presents, in all material respects, the financial condition and results of operations of Gulf Power Company.

/s/S. W. Connally, Jr.

S. W. Connally, Jr.

Chairman, President and Chief Executive Officer

/s/Xia Liu

Xia Liu

Vice President and Chief Financial Officer

May 5, 2016

EX-32.E

Exhibit 32(e)

CERTIFICATION

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the accompanying Quarterly Report on Form 10-Q of Mississippi Power Company for the quarter ended March 31, 2016, we, the undersigned, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of our individual knowledge and belief, that:

(1) such Quarterly Report on Form 10-Q of Mississippi Power Company for the quarter ended March 31, 2016, which this statement accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in such Quarterly Report on Form 10-Q of Mississippi Power Company for the quarter ended March 31, 2016, fairly presents, in all material respects, the financial condition and results of operations of Mississippi Power Company.

/s/Anthony L. Wilson

Anthony L. Wilson

President and Chief Executive Officer

/s/Moses H. Feagin

Moses H. Feagin

Vice President, Treasurer and

Chief Financial Officer

May 5, 2016

EX-32.F

Exhibit 32(f)

CERTIFICATION

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the accompanying Quarterly Report on Form 10-Q of Southern Power Company for the quarter ended March 31, 2016, we, the undersigned, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of our individual knowledge and belief, that:

(1) such Quarterly Report on Form 10-Q of Southern Power Company for the quarter ended March 31, 2016, which this statement accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in such Quarterly Report on Form 10-Q of Southern Power Company for the quarter ended March 31, 2016, fairly presents, in all material respects, the financial condition and results of operations of Southern Power Company.

/s/Joseph A. Miller

Joseph A. Miller

President and Chief Executive Officer

/s/William C. Grantham

William C. Grantham

Vice President, Treasurer and

Chief Financial Officer

May 5, 2016

XML

Document and Entity Information	3 Months Ended
	Mar. 31, 2016 shares
Document Information [Line Items]
Entity Registrant Name	SOUTHERN CO
Entity Central Index Key	0000092122
Document Type	10-Q
Document Period End Date	Mar. 31, 2016
Amendment Flag	false
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	Q1
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding	918,258,425
Alabama Power [Member]
Document Information [Line Items]
Entity Registrant Name	ALABAMA POWER CO
Entity Central Index Key	0000003153
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding	30,537,500
Georgia Power [Member]
Document Information [Line Items]
Entity Registrant Name	GEORGIA POWER CO
Entity Central Index Key	0000041091
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding	9,261,500
Gulf Power [Member]
Document Information [Line Items]
Entity Registrant Name	GULF POWER CO
Entity Central Index Key	0000044545
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding	5,642,717
Mississippi Power [Member]
Document Information [Line Items]
Entity Registrant Name	MISSISSIPPI POWER CO
Entity Central Index Key	0000066904
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding	1,121,000
Southern Power [Member]
Document Information [Line Items]
Entity Registrant Name	SOUTHERN POWER CO
Entity Central Index Key	0001160661
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding	1,000

XML

Condensed Consolidated Statements of Income (Unaudited) - USD ($) shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Operating Revenues:
Retail revenues	$ 3,377	$ 3,542
Wholesale revenues	396	467
Other electric revenues	181	163
Other revenues	11	11
Total operating revenues	3,965	4,183
Operating Expenses:
Fuel	911	1,212
Purchased power	165	144
Other operations and maintenance	1,106	1,122
Depreciation and amortization	541	487
Taxes other than income taxes	256	252
Estimated loss on Kemper IGCC	53	9
Total operating expenses	3,032	3,226
Operating Income (Loss)	933	957
Other Income and (Expense):
Allowance for equity funds used during construction	53	63
Interest expense, net of amounts capitalized	(246)	(213)
Other income (expense), net	(21)	(8)
Total other income and (expense)	(214)	(158)
Earnings Before Income Taxes	719	799
Income taxes (benefit)	222	274
Net Income (Loss)	497	525
Less: Net income attributable to noncontrolling interests	1	0
Dividends on preferred and preference stock of subsidiaries	11	17
Net Income (Loss) After Dividends on Preferred and Preference Stock of Subsidiaries	$ 485	$ 508
Earnings per share (EPS) -
Basic EPS (in dollars per share)	$ 0.53	$ 0.56
Diluted EPS (in dollars per share)	$ 0.53	$ 0.56
Average number of shares of common stock outstanding (in millions)
Basic (in shares)	916	910
Diluted (in shares)	922	915
Cash dividends paid per share of common stock (in dollars per share)	$ 0.5425	$ 0.525
Alabama Power [Member]
Operating Revenues:
Retail revenues	$ 1,193	$ 1,268
Wholesale revenues, non-affiliates	63	65
Wholesale revenues, affiliates	22	15
Other revenues	53	53
Total operating revenues	1,331	1,401
Operating Expenses:
Fuel	268	310
Purchased power, non-affiliates	36	41
Purchased power, affiliates	33	53
Other operations and maintenance	392	399
Depreciation and amortization	172	158
Taxes other than income taxes	97	94
Total operating expenses	998	1,055
Operating Income (Loss)	333	346
Other Income and (Expense):
Allowance for equity funds used during construction	10	15
Interest expense, net of amounts capitalized	(73)	(65)
Other income (expense), net	(8)	(4)
Total other income and (expense)	(71)	(54)
Earnings Before Income Taxes	262	292
Income taxes (benefit)	103	113
Net Income (Loss)	159	179
Dividends on preferred and preference stock of subsidiaries	4	10
Net Income (Loss) After Dividends on Preferred and Preference Stock of Subsidiaries	155	169
Georgia Power [Member]
Operating Revenues:
Retail revenues	1,717	1,814
Wholesale revenues, non-affiliates	41	68
Wholesale revenues, affiliates	5	8
Other revenues	109	88
Total operating revenues	1,872	1,978
Operating Expenses:
Fuel	376	526
Purchased power, non-affiliates	83	60
Purchased power, affiliates	139	149
Other operations and maintenance	457	474
Depreciation and amortization	211	216
Taxes other than income taxes	97	99
Total operating expenses	1,363	1,524
Operating Income (Loss)	509	454
Other Income and (Expense):
Allowance for equity funds used during construction	14	15
Interest expense, net of amounts capitalized	(94)	(89)
Other income (expense), net	17	15
Total other income and (expense)	(77)	(74)
Earnings Before Income Taxes	432	380
Income taxes (benefit)	160	140
Net Income (Loss)	272	240
Dividends on preferred and preference stock of subsidiaries	4	4
Net Income (Loss) After Dividends on Preferred and Preference Stock of Subsidiaries	268	236
Gulf Power [Member]
Operating Revenues:
Retail revenues	283	293
Wholesale revenues, non-affiliates	16	25
Wholesale revenues, affiliates	21	22
Other revenues	15	17
Total operating revenues	335	357
Operating Expenses:
Fuel	94	110
Purchased power, non-affiliates	30	25
Purchased power, affiliates	2	9
Other operations and maintenance	77	93
Depreciation and amortization	38	20
Taxes other than income taxes	29	28
Total operating expenses	270	285
Operating Income (Loss)	65	72
Other Income and (Expense):
Allowance for equity funds used during construction	0	4
Interest expense, net of amounts capitalized	(13)	(13)
Other income (expense), net	(1)	(1)
Total other income and (expense)	(14)	(10)
Earnings Before Income Taxes	51	62
Income taxes (benefit)	20	23
Net Income (Loss)	31	39
Dividends on preferred and preference stock of subsidiaries	2	2
Net Income (Loss) After Dividends on Preferred and Preference Stock of Subsidiaries	29	37
Mississippi Power [Member]
Operating Revenues:
Retail revenues	183	167
Wholesale revenues, non-affiliates	60	77
Wholesale revenues, affiliates	9	27
Other revenues	5	5
Total operating revenues	257	276
Operating Expenses:
Fuel	76	114
Purchased power, non-affiliates	0	2
Purchased power, affiliates	5	2
Other operations and maintenance	69	73
Depreciation and amortization	38	27
Taxes other than income taxes	26	25
Estimated loss on Kemper IGCC	53	9
Total operating expenses	267	252
Operating Income (Loss)	(10)	24
Other Income and (Expense):
Allowance for equity funds used during construction	29	28
Interest expense, net of amounts capitalized	(16)	(11)
Other income (expense), net	(2)	(2)
Total other income and (expense)	11	15
Earnings Before Income Taxes	1	39
Income taxes (benefit)	(10)	4
Net Income (Loss)	11	35
Dividends on preferred and preference stock of subsidiaries	0	0
Net Income (Loss) After Dividends on Preferred and Preference Stock of Subsidiaries	11	35
Southern Power [Member]
Operating Revenues:
Wholesale revenues, non-affiliates	215	232
Wholesale revenues, affiliates	97	114
Other revenues	3	2
Total operating revenues	315	348
Operating Expenses:
Fuel	91	138
Purchased power, non-affiliates	13	16
Purchased power, affiliates	6	10
Other operations and maintenance	79	52
Depreciation and amortization	73	59
Taxes other than income taxes	6	6
Total operating expenses	268	281
Operating Income (Loss)	47	67
Other Income and (Expense):
Interest expense, net of amounts capitalized	(21)	(22)
Other income (expense), net	2	0
Total other income and (expense)	(19)	(22)
Earnings Before Income Taxes	28	45
Income taxes (benefit)	(23)	12
Net Income (Loss)	51	33
Less: Net income attributable to noncontrolling interests	1	0
Net income attributable to Southern Power Company	$ 50	$ 33

XML

Condensed Consolidated Statements of Comprehensive Income (Unaudited) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Net Income (loss)	$ 497	$ 525
Qualifying hedges:
Changes in fair value, net of tax	(117)	(18)
Reclassification adjustment for amounts included in net income, net of tax	2	1
Pension and other post retirement benefit plans:
Reclassification adjustment for amounts included in net income, net of tax	1	2
Total other comprehensive income (loss)	(114)	(15)
Dividends on preferred and preference stock of subsidiaries	11	17
Comprehensive income attributable to noncontrolling interests	1	0
Comprehensive Income (Loss)	371	493
Alabama Power [Member]
Net Income (loss)	159	179
Qualifying hedges:
Changes in fair value, net of tax	(2)	(4)
Reclassification adjustment for amounts included in net income, net of tax	1	0
Pension and other post retirement benefit plans:
Total other comprehensive income (loss)	(1)	(4)
Dividends on preferred and preference stock of subsidiaries	4	10
Comprehensive Income (Loss)	158	175
Georgia Power [Member]
Net Income (loss)	272	240
Qualifying hedges:
Changes in fair value, net of tax	0	(14)
Reclassification adjustment for amounts included in net income, net of tax	1	0
Pension and other post retirement benefit plans:
Total other comprehensive income (loss)	1	(14)
Dividends on preferred and preference stock of subsidiaries	4	4
Comprehensive Income (Loss)	273	226
Gulf Power [Member]
Net Income (loss)	31	39
Qualifying hedges:
Changes in fair value, net of tax	(3)	0
Pension and other post retirement benefit plans:
Total other comprehensive income (loss)	(3)	0
Dividends on preferred and preference stock of subsidiaries	2	2
Comprehensive Income (Loss)	28	39
Mississippi Power [Member]
Net Income (loss)	11	35
Pension and other post retirement benefit plans:
Total other comprehensive income (loss)	0	0
Dividends on preferred and preference stock of subsidiaries	0	0
Comprehensive Income (Loss)	11	35
Southern Power [Member]
Net Income (loss)	51	33
Qualifying hedges:
Reclassification adjustment for amounts included in net income, net of tax	1	0
Pension and other post retirement benefit plans:
Total other comprehensive income (loss)	1	0
Comprehensive income attributable to noncontrolling interests	1	0
Comprehensive Income (Loss)	$ 51	$ 33

XML

Condensed Consolidated Statements of Comprehensive Income (Unaudited) (Parenthetical) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Changes in fair value, tax	$ (72)	$ (11)
Reclassification adjustment for amounts of qualifying hedges included in net income, tax	1	1
Reclassification adjustment for amounts of pension and other post retirement benefit plans included in net income, tax	1	1
Alabama Power [Member]
Changes in fair value, tax	(1)	(2)
Reclassification adjustment for amounts of qualifying hedges included in net income, tax	1	0
Gulf Power [Member]
Reclassification adjustment for amounts of qualifying hedges included in net income, tax	(2)	0
Southern Power [Member]
Reclassification adjustment for amounts of qualifying hedges included in net income, tax	0	0
Georgia Power [Member]
Changes in fair value, tax	0	(9)
Reclassification adjustment for amounts of qualifying hedges included in net income, tax	$ 0	$ 0

XML

Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Operating Activities:
Net income (loss)	$ 497	$ 525
Adjustments to reconcile net income (loss) to net cash provided from operating activities —
Depreciation and amortization, total	639	578
Deferred income taxes	(4)	113
Allowance for equity funds used during construction	(53)	(63)
Stock based compensation expense	58	56
Estimated loss on Kemper IGCC	53	9
Other, net	(13)	4
Changes in certain current assets and liabilities —
-Receivables	235	180
-Fossil fuel stock	31	76
-Materials and supplies	(14)	4
-Other current assets	(90)	(89)
-Accounts payable	(72)	(426)
-Accrued taxes	(60)	197
-Accrued compensation	(332)	(381)
-Retail fuel cost over recovery - short-term	25	49
-Mirror CWIP	0	40
-Other current liabilities	(35)	41
Net cash provided from (used for) operating activities	865	913
Investing Activities:
Plant acquisitions	(114)	(6)
Property additions	(1,872)	(1,091)
Investment in restricted cash	(289)	0
Distributions of restricted cash	292	0
Nuclear decommissioning trust fund purchases	(316)	(290)
Nuclear decommissioning trust fund sales	311	284
Cost of removal, net of salvage	(52)	(36)
Change in construction payables	(94)	65
Prepaid long-term service agreement	(49)	(37)
Other investing activities	(14)	4
Net cash used for investing activities	(2,197)	(1,107)
Financing Activities:
Increase (decrease) in notes payable, net	294	597
Proceeds —
Long-term debt issuances	1,997	550
Common stock issuances	270	112
Short-term borrowings	0	280
Redemptions and repurchases —
Long-term debt	(888)	(333)
Common stock	0	(115)
Short-term borrowings	(475)	0
Capital contributions from noncontrolling interests	131	0
Purchase of membership interests from noncontrolling interests	(4)	0
Purchase of Membership Interests from Noncontrolling Interests	(129)	0
Payment of common stock dividends	(497)	(478)
Other financing activities	(17)	(17)
Net cash provided from (used for) financing activities	682	596
Net Change in Cash and Cash Equivalents	(650)	402
Cash and Cash Equivalents at Beginning of Period	1,404	710
Cash and Cash Equivalents at End of Period	754	1,112
Cash paid (received) during the period for --
Interest (net of capitalized amounts)	224	207
Income taxes, net	(141)	(289)
Noncash transactions - Accrued property additions at end of period	731	347
Alabama Power [Member]
Operating Activities:
Net income (loss)	159	179
Adjustments to reconcile net income (loss) to net cash provided from operating activities —
Depreciation and amortization, total	211	196
Deferred income taxes	68	16
Allowance for equity funds used during construction	(10)	(15)
Other, net	(3)	2
Changes in certain current assets and liabilities —
-Receivables	191	(3)
-Fossil fuel stock	(27)	0
-Materials and supplies	(8)	12
-Other current assets	(79)	(80)
-Accounts payable	(143)	(229)
-Accrued taxes	64	246
-Accrued compensation	(75)	(89)
-Retail fuel cost over recovery - short-term	(1)	34
-Other current liabilities	(8)	21
Net cash provided from (used for) operating activities	339	290
Investing Activities:
Property additions	(313)	(325)
Nuclear decommissioning trust fund purchases	(105)	(129)
Nuclear decommissioning trust fund sales	105	129
Cost of removal, net of salvage	(31)	(13)
Change in construction payables	(15)	34
Other investing activities	(9)	(9)
Net cash used for investing activities	(368)	(313)
Proceeds —
Senior notes issuances	400	550
Capital contributions from parent company	236	6
Other long-term debt	45	0
Redemptions and repurchases —
Senior notes	(200)	(250)
Payment of common stock dividends	(191)	(143)
Other financing activities	(11)	(18)
Net cash provided from (used for) financing activities	279	145
Net Change in Cash and Cash Equivalents	250	122
Cash and Cash Equivalents at Beginning of Period	194	273
Cash and Cash Equivalents at End of Period	444	395
Cash paid (received) during the period for --
Interest (net of capitalized amounts)	76	68
Income taxes, net	(162)	(136)
Noncash transactions - Accrued property additions at end of period	106	41
Georgia Power [Member]
Operating Activities:
Net income (loss)	272	240
Adjustments to reconcile net income (loss) to net cash provided from operating activities —
Depreciation and amortization, total	261	256
Deferred income taxes	55	(7)
Allowance for equity funds used during construction	(14)	(15)
Deferred expenses	38	33
Other, net	(9)	4
Changes in certain current assets and liabilities —
-Receivables	155	166
-Fossil fuel stock	36	67
-Prepaid income taxes	38	170
-Other current assets	12	(13)
-Accounts payable	4	(261)
-Accrued taxes	(235)	(217)
-Accrued compensation	(66)	(81)
-Other current liabilities	16	21
Net cash provided from (used for) operating activities	563	363
Investing Activities:
Property additions	(553)	(422)
Nuclear decommissioning trust fund purchases	(211)	(161)
Nuclear decommissioning trust fund sales	206	155
Cost of removal, net of salvage	(15)	(16)
Change in construction payables, net of joint owner portion	(101)	37
Prepaid long-term service agreement	(11)	(9)
Other investing activities	(4)	11
Net cash used for investing activities	(689)	(405)
Financing Activities:
Increase (decrease) in notes payable, net	(158)	434
Proceeds —
Senior notes issuances	650	0
Capital contributions from parent company	218	11
Short-term borrowings	0	250
Redemptions and repurchases —
Pollution control revenue bonds	(4)	0
Senior notes	(250)	0
Payment of common stock dividends	(326)	(259)
Other financing activities	(11)	(5)
Net cash provided from (used for) financing activities	119	431
Net Change in Cash and Cash Equivalents	(7)	389
Cash and Cash Equivalents at Beginning of Period	67	24
Cash and Cash Equivalents at End of Period	60	413
Cash paid (received) during the period for --
Interest (net of capitalized amounts)	86	79
Income taxes, net	(88)	(34)
Noncash transactions - Accrued property additions at end of period	290	177
Gulf Power [Member]
Operating Activities:
Net income (loss)	31	39
Adjustments to reconcile net income (loss) to net cash provided from operating activities —
Depreciation and amortization, total	40	22
Deferred income taxes	9	27
Allowance for equity funds used during construction	0	(4)
Other, net	(2)	11
Changes in certain current assets and liabilities —
-Receivables	35	12
-Fossil fuel stock	15	(2)
-Other current assets	2	5
-Accounts payable	(6)	(28)
-Accrued taxes	13	5
-Accrued compensation	(18)	(16)
-Other current liabilities	13	10
Net cash provided from (used for) operating activities	132	81
Investing Activities:
Property additions	(32)	(84)
Cost of removal, net of salvage	(2)	(5)
Change in construction payables	(6)	(1)
Other investing activities	(2)	(2)
Net cash used for investing activities	(42)	(92)
Financing Activities:
Increase (decrease) in notes payable, net	(85)	40
Proceeds —
Common stock issuances	0	20
Redemptions and repurchases —
Payment of common stock dividends	(30)	(33)
Other financing activities	(1)	0
Net cash provided from (used for) financing activities	(116)	27
Net Change in Cash and Cash Equivalents	(26)	16
Cash and Cash Equivalents at Beginning of Period	74	39
Cash and Cash Equivalents at End of Period	48	55
Cash paid (received) during the period for --
Interest (net of capitalized amounts)	3	3
Income taxes, net	(25)	(8)
Noncash transactions - Accrued property additions at end of period	15	41
Mississippi Power [Member]
Operating Activities:
Net income (loss)	11	35
Adjustments to reconcile net income (loss) to net cash provided from operating activities —
Depreciation and amortization, total	39	26
Deferred income taxes	(4)	141
Allowance for equity funds used during construction	(29)	(28)
Regulatory assets associated with Kemper IGCC	(6)	(27)
Estimated loss on Kemper IGCC	53	9
Other, net	1	11
Changes in certain current assets and liabilities —
-Receivables	45	17
-Fossil fuel stock	6	4
-Prepaid income taxes	(3)	44
-Other current assets	(5)	(3)
-Accounts payable	(22)	(22)
-Accrued taxes	(61)	(54)
-Accrued interest	2	9
-Accrued compensation	(16)	(20)
-Over recovered regulatory clause revenues	9	22
-Mirror CWIP	0	40
-Customer liability associated with Kemper refunds	(51)	0
-Other current liabilities	6	0
Net cash provided from (used for) operating activities	(25)	204
Investing Activities:
Property additions	(197)	(213)
Change in construction payables	(7)	(14)
Other investing activities	(10)	(6)
Net cash used for investing activities	(214)	(233)
Proceeds —
Capital contributions from parent company	1	76
Short-term borrowings	0	30
Long-term debt issuance to parent company	200	0
Other long-term debt	900	0
Redemptions and repurchases —
Short-term borrowings	(475)	0
Other long-term debt	(425)	(75)
Other financing activities	(2)	(1)
Net cash provided from (used for) financing activities	199	30
Net Change in Cash and Cash Equivalents	(40)	1
Cash and Cash Equivalents at Beginning of Period	98	133
Cash and Cash Equivalents at End of Period	58	134
Cash paid (received) during the period for --
Interest (net of capitalized amounts)	12	(1)
Income taxes, net	(24)	(180)
Noncash transactions - Accrued property additions at end of period	97	100
Southern Power [Member]
Operating Activities:
Net income (loss)	51	33
Adjustments to reconcile net income (loss) to net cash provided from operating activities —
Depreciation and amortization, total	75	60
Deferred income taxes	(132)	(54)
Amortization of investment tax credits	(7)	(4)
Deferred revenues	(26)	(20)
Other, net	9	3
Changes in certain current assets and liabilities —
-Receivables	(3)	2
-Fossil fuel stock	1	6
-Prepaid income taxes	(31)	(2)
-Accounts payable	(12)	(25)
-Accrued taxes	(37)	(4)
-Accrued interest	2	(15)
-Other current liabilities	0	1
Net cash provided from (used for) operating activities	(110)	(19)
Investing Activities:
Plant acquisitions	(114)	(6)
Property additions	(767)	(33)
Investment in restricted cash	(289)	0
Distributions of restricted cash	292	0
Change in construction payables	31	17
Payments pursuant to long-term service agreements	(25)	(16)
Other investing activities	(1)	0
Net cash used for investing activities	(873)	(38)
Financing Activities:
Increase (decrease) in notes payable, net	276	38
Redemptions and repurchases —
Capital contributions from noncontrolling interests	131	0
Purchase of membership interests from noncontrolling interests	(4)	0
Purchase of Membership Interests from Noncontrolling Interests	(129)	0
Payment of common stock dividends	(68)	(33)
Net cash provided from (used for) financing activities	206	5
Net Change in Cash and Cash Equivalents	(777)	(52)
Cash and Cash Equivalents at Beginning of Period	830	75
Cash and Cash Equivalents at End of Period	53	23
Cash paid (received) during the period for --
Interest (net of capitalized amounts)	15	36
Income taxes, net	188	79
Noncash transactions - Accrued property additions at end of period	$ 262	$ 16

XML

Condensed Consolidated Statements of Cash Flows (Unaudited) (Parenthetical) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Net cash paid for capitalized interest	$ 30	$ 32
Alabama Power [Member]
Net cash paid for capitalized interest	4	5
Georgia Power [Member]
Net cash paid for capitalized interest	5	6
Gulf Power [Member]
Net cash paid for capitalized interest	0	2
Mississippi Power [Member]
Interest paid	22	17
Net cash paid for capitalized interest	10	18
Southern Power [Member]
Net cash paid for capitalized interest	$ 10	$ 0

XML

Condensed Consolidated Balance Sheets (Unaudited) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Current Assets:
Cash and cash equivalents	$ 754	$ 1,404
Receivables —
Customer accounts receivable	988	1,058
Unbilled revenues	380	397
Under recovered regulatory clause revenues	43	63
Income taxes receivable, current	0	144
Other accounts and notes receivable	236	398
Accumulated provision for uncollectible accounts	(13)	(13)
Fossil fuel stock, at average cost	837	868
Materials and supplies, at average cost	1,085	1,061
Vacation pay	181	178
Other regulatory assets, current	394	402
Prepaid expenses	486	495
Other current assets	90	71
Total current assets	5,461	6,526
Property, Plant, and Equipment:
In service	76,553	75,118
Less accumulated provision for depreciation	24,566	24,253
Plant in service, net of depreciation	51,987	50,865
Other utility plant, net	218	233
Nuclear fuel, at amortized cost	941	934
Construction work in progress	9,406	9,082
Total property, plant, and equipment	62,552	61,114
Other Property and Investments:
Nuclear decommissioning trusts, at fair value	1,540	1,512
Leveraged leases	761	755
Miscellaneous property and investments	488	485
Total other property and investments	2,789	2,752
Deferred Charges and Other Assets:
Deferred charges related to income taxes	1,572	1,560
Unamortized loss on reacquired debt	220	227
Other regulatory assets, deferred	4,957	4,989
Income taxes receivable, non-current	413	413
Other deferred charges and assets	771	737
Total deferred charges and other assets	7,933	7,926
Total Assets	78,735	78,318
Current Liabilities:
Securities due within one year	2,392	2,674
Notes payable	1,195	1,376
Accounts payable —
Accounts payable	1,584	1,905
Customer deposits	406	404
Accrued taxes —
Accrued income taxes	14	19
Other accrued taxes	240	484
Accrued interest	255	249
Accrued vacation pay	228	228
Accrued compensation	212	549
Asset retirement obligations, current	237	217
Liabilities from risk management activities	319	156
Other regulatory liabilities, current	210	278
Other current liabilities	564	590
Total current liabilities	7,856	9,129
Long-term Debt:
Total Long-term Debt	26,091	24,688
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	12,274	12,322
Deferred credits related to income taxes	185	187
Accumulated deferred investment tax credits	1,350	1,219
Employee benefit obligations	2,546	2,582
Asset retirement obligations, deferred	3,504	3,542
Unrecognized tax benefits	375	370
Other cost of removal obligations	1,151	1,162
Other regulatory liabilities, deferred	303	254
Other deferred credits and liabilities	754	720
Total deferred credits and other liabilities	22,442	22,358
Total Liabilities	56,389	56,175
Redeemable Preferred Stock of Subsidiaries	118	118
Redeemable Noncontrolling Interest	44	43
Common Stockholders' Equity:
Common stock	4,604	4,572
Paid-in capital	6,582	6,282
Treasury, at cost	(144)	(142)
Retained earnings (accumulated deficit)	9,999	10,010
Accumulated other comprehensive income (loss)	(244)	(130)
Total common stockholders' equity	20,797	20,592
Preferred and Preference Stock of Subsidiaries	609	609
Noncontrolling Interests	778	781
Total Stockholders' Equity	22,184	21,982
Total Liabilities and Stockholders' Equity	78,735	78,318
Alabama Power [Member]
Current Assets:
Cash and cash equivalents	444	194
Receivables —
Customer accounts receivable	311	332
Unbilled revenues	113	119
Under recovered regulatory clause revenues	22	43
Income taxes receivable, current	0	142
Other accounts and notes receivable	25	20
Affiliated companies	38	50
Accumulated provision for uncollectible accounts	(10)	(10)
Fossil fuel stock, at average cost	266	239
Materials and supplies, at average cost	406	398
Vacation pay	67	66
Other regulatory assets, current	99	115
Prepaid expenses	129	83
Other current assets	10	10
Total current assets	1,920	1,801
Property, Plant, and Equipment:
In service	25,187	24,750
Less accumulated provision for depreciation	8,791	8,736
Plant in service, net of depreciation	16,396	16,014
Nuclear fuel, at amortized cost	359	363
Construction work in progress	550	801
Total property, plant, and equipment	17,305	17,178
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	68	71
Nuclear decommissioning trusts, at fair value	746	737
Miscellaneous property and investments	99	96
Total other property and investments	913	904
Deferred Charges and Other Assets:
Deferred charges related to income taxes	520	522
Deferred under recovered regulatory clause revenues	105	99
Other regulatory assets, deferred	1,105	1,114
Other deferred charges and assets	109	103
Total deferred charges and other assets	1,839	1,838
Total Assets	21,977	21,721
Current Liabilities:
Securities due within one year	200	200
Accounts payable —
Affiliated accounts payable	258	278
Other accounts payable	271	410
Customer deposits	88	88
Accrued taxes —
Accrued income taxes	11	0
Other accrued taxes	62	38
Accrued interest	65	73
Accrued vacation pay	55	55
Accrued compensation	47	119
Liabilities from risk management activities	37	55
Other regulatory liabilities, current	175	240
Other current liabilities	39	39
Total current liabilities	1,308	1,595
Long-term Debt:
Total Long-term Debt	6,894	6,654
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	4,306	4,241
Deferred credits related to income taxes	69	70
Accumulated deferred investment tax credits	116	118
Employee benefit obligations	377	388
Asset retirement obligations, deferred	1,461	1,448
Other cost of removal obligations	705	722
Other regulatory liabilities, deferred	119	136
Deferred over recovered regulatory clause revenues	64	0
Other deferred credits and liabilities	78	76
Total deferred credits and other liabilities	7,295	7,199
Total Liabilities	15,497	15,448
Redeemable Preferred Stock	85	85
Preference Stock	196	196
Common Stockholders' Equity:
Common stock	1,222	1,222
Paid-in capital	2,585	2,341
Retained earnings (accumulated deficit)	2,425	2,461
Accumulated other comprehensive income (loss)	(33)	(32)
Total common stockholders' equity	6,199	5,992
Total Liabilities and Stockholders' Equity	21,977	21,721
Georgia Power [Member]
Current Assets:
Cash and cash equivalents	60	67
Receivables —
Customer accounts receivable	509	541
Unbilled revenues	182	188
Joint owner accounts receivable	73	227
Income taxes receivable, current	0	114
Other accounts and notes receivable	37	57
Affiliated companies	16	18
Accumulated provision for uncollectible accounts	(2)	(2)
Fossil fuel stock, at average cost	366	402
Materials and supplies, at average cost	463	449
Vacation pay	92	91
Other regulatory assets, current	126	123
Prepaid income taxes	118	156
Other current assets	61	92
Total current assets	2,101	2,523
Property, Plant, and Equipment:
In service	32,318	31,841
Less accumulated provision for depreciation	11,045	10,903
Plant in service, net of depreciation	21,273	20,938
Other utility plant, net	158	171
Nuclear fuel, at amortized cost	582	572
Construction work in progress	4,817	4,775
Total property, plant, and equipment	26,830	26,456
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	60	64
Nuclear decommissioning trusts, at fair value	793	775
Miscellaneous property and investments	43	43
Total other property and investments	896	882
Deferred Charges and Other Assets:
Deferred charges related to income taxes	680	679
Other regulatory assets, deferred	2,138	2,152
Other deferred charges and assets	157	173
Total deferred charges and other assets	2,975	3,004
Total Assets	32,802	32,865
Current Liabilities:
Securities due within one year	458	712
Notes payable	0	158
Accounts payable —
Affiliated accounts payable	370	411
Other accounts payable	549	750
Customer deposits	266	264
Accrued taxes —
Accrued income taxes	0	12
Other accrued taxes	101	325
Accrued interest	102	99
Accrued vacation pay	62	62
Accrued compensation	60	142
Asset retirement obligations, current	184	179
Other current liabilities	211	181
Total current liabilities	2,363	3,295
Long-term Debt:
Total Long-term Debt	10,268	9,616
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	5,686	5,627
Deferred credits related to income taxes	105	105
Accumulated deferred investment tax credits	201	204
Employee benefit obligations	930	949
Asset retirement obligations, deferred	1,699	1,737
Other deferred credits and liabilities	395	347
Total deferred credits and other liabilities	9,016	8,969
Total Liabilities	21,647	21,880
Redeemable Preferred Stock	45	45
Preference Stock	221	221
Common Stockholders' Equity:
Common stock	398	398
Paid-in capital	6,504	6,275
Retained earnings (accumulated deficit)	4,002	4,061
Accumulated other comprehensive income (loss)	(15)	(15)
Total common stockholders' equity	10,889	10,719
Total Liabilities and Stockholders' Equity	32,802	32,865
Gulf Power [Member]
Current Assets:
Cash and cash equivalents	48	74
Receivables —
Customer accounts receivable	64	76
Unbilled revenues	52	54
Under recovered regulatory clause revenues	21	20
Income taxes receivable, current	0	27
Other accounts and notes receivable	5	9
Affiliated companies	8	1
Accumulated provision for uncollectible accounts	(1)	(1)
Fossil fuel stock, at average cost	93	108
Materials and supplies, at average cost	58	56
Other regulatory assets, current	90	90
Other current assets	18	22
Total current assets	456	536
Property, Plant, and Equipment:
In service	5,058	5,045
Less accumulated provision for depreciation	1,324	1,296
Plant in service, net of depreciation	3,734	3,749
Other utility plant, net	60	62
Construction work in progress	57	48
Total property, plant, and equipment	3,851	3,859
Other Property and Investments:
Total other property and investments	4	4
Deferred Charges and Other Assets:
Deferred charges related to income taxes	60	61
Other regulatory assets, deferred	420	427
Other deferred charges and assets	37	33
Total deferred charges and other assets	517	521
Total Assets	4,828	4,920
Current Liabilities:
Securities due within one year	110	110
Notes payable	56	142
Accounts payable —
Affiliated accounts payable	46	55
Other accounts payable	42	44
Customer deposits	36	36
Accrued taxes —
Accrued income taxes	10	4
Other accrued taxes	16	9
Accrued interest	20	9
Accrued compensation	8	25
Deferred capacity expense, current	22	22
Liabilities from risk management activities	54	49
Other regulatory liabilities, current	22	22
Other current liabilities	38	40
Total current liabilities	480	567
Long-term Debt:
Total Long-term Debt	1,193	1,193
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	899	893
Employee benefit obligations	128	129
Deferred capacity expense	136	141
Asset retirement obligations, deferred	114	113
Other cost of removal obligations	233	233
Other regulatory liabilities, deferred	45	47
Other deferred credits and liabilities	100	102
Total deferred credits and other liabilities	1,655	1,658
Total Liabilities	3,328	3,418
Preference Stock	147	147
Common Stockholders' Equity:
Common stock	503	503
Paid-in capital	569	567
Retained earnings (accumulated deficit)	284	285
Accumulated other comprehensive income (loss)	(3)	0
Total common stockholders' equity	1,353	1,355
Total Liabilities and Stockholders' Equity	4,828	4,920
Mississippi Power [Member]
Current Assets:
Cash and cash equivalents	58	98
Receivables —
Customer accounts receivable	23	26
Unbilled revenues	32	36
Income taxes receivable, current	0	20
Other accounts and notes receivable	6	10
Affiliated companies	7	20
Fossil fuel stock, at average cost	99	104
Materials and supplies, at average cost	76	75
Other regulatory assets, current	101	95
Prepaid income taxes	42	39
Other current assets	5	8
Total current assets	449	531
Property, Plant, and Equipment:
In service	4,905	4,886
Less accumulated provision for depreciation	1,287	1,262
Plant in service, net of depreciation	3,618	3,624
Construction work in progress	2,400	2,254
Total property, plant, and equipment	6,018	5,878
Other Property and Investments:
Total other property and investments	11	11
Deferred Charges and Other Assets:
Deferred charges related to income taxes	303	290
Other regulatory assets, deferred	520	525
Income taxes receivable, non-current	544	544
Other deferred charges and assets	71	61
Total deferred charges and other assets	1,438	1,420
Total Assets	7,916	7,840
Current Liabilities:
Securities due within one year	303	728
Notes payable	25	500
Accounts payable —
Affiliated accounts payable	82	85
Other accounts payable	108	135
Customer deposits	16	16
Accrued taxes —
Accrued income taxes	25	85
Accrued interest	21	18
Accrued compensation	10	26
Asset retirement obligations, current	39	22
Over recovered regulatory clause liabilities	106	96
Customer liability associated with Kemper refunds	22	73
Other current liabilities	55	52
Total current liabilities	812	1,836
Long-term Debt:
Long-term debt, affiliated	776	576
Long-term debt, non-affiliated	2,206	1,310
Total Long-term Debt	2,982	1,886
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	771	762
Deferred credits related to income taxes	8	8
Accumulated deferred investment tax credits	5	5
Employee benefit obligations	149	153
Asset retirement obligations, deferred	136	154
Unrecognized tax benefits	368	368
Other cost of removal obligations	167	165
Other regulatory liabilities, deferred	71	71
Other deferred credits and liabilities	41	40
Total deferred credits and other liabilities	1,716	1,726
Total Liabilities	5,510	5,448
Redeemable Preferred Stock	33	33
Common Stockholders' Equity:
Common stock	38	38
Paid-in capital	2,896	2,893
Retained earnings (accumulated deficit)	(555)	(566)
Accumulated other comprehensive income (loss)	(6)	(6)
Total common stockholders' equity	2,373	2,359
Total Liabilities and Stockholders' Equity	7,916	7,840
Southern Power [Member]
Current Assets:
Cash and cash equivalents	53	830
Receivables —
Customer accounts receivable	76	75
Other accounts and notes receivable	23	19
Affiliated companies	31	30
Fossil fuel stock, at average cost	14	16
Materials and supplies, at average cost	63	63
Prepaid income taxes	77	45
Prepaid expenses	23	23
Assets from risk management activities	6	7
Total current assets	366	1,108
Property, Plant, and Equipment:
In service	7,738	7,275
Less accumulated provision for depreciation	1,299	1,248
Plant in service, net of depreciation	6,439	6,027
Construction work in progress	1,535	1,137
Total property, plant, and equipment	7,974	7,164
Other Property and Investments:
Goodwill	2	2
Other intangible assets, net of amortization	316	317
Total other property and investments	318	319
Deferred Charges and Other Assets:
Prepaid long-term service agreements	184	166
Other deferred charges and assets -- affiliated	20	9
Other deferred charges and assets	137	139
Total deferred charges and other assets	341	314
Total Assets	8,999	8,905
Current Liabilities:
Securities due within one year	401	403
Notes payable	413	137
Accounts payable —
Affiliated accounts payable	62	66
Other accounts payable	347	327
Accrued taxes —
Accrued income taxes	9	198
Other accrued taxes	16	5
Accrued interest	25	23
Contingent consideration	21	36
Other current liabilities	49	44
Total current liabilities	1,343	1,239
Long-term Debt:
Total Long-term Debt	2,722	2,719
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	470	601
Accumulated deferred investment tax credits	1,025	889
Accrued income taxes, non-current	109	109
Asset retirement obligations, deferred	25	21
Deferred capacity revenues -- affiliated	6	17
Other deferred credits and liabilities	11	3
Total deferred credits and other liabilities	1,646	1,640
Total Liabilities	5,711	5,598
Redeemable Noncontrolling Interest	44	43
Common Stockholders' Equity:
Common stock	0	0
Paid-in capital	1,821	1,822
Retained earnings (accumulated deficit)	640	657
Accumulated other comprehensive income (loss)	5	4
Total common stockholders' equity	2,466	2,483
Noncontrolling Interests, Total	778	781
Total Stockholders' Equity	3,244	3,264
Total Liabilities and Stockholders' Equity	$ 8,999	$ 8,905

XML

Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Common stock, par value (in dollars per share)	$ 5	$ 5
Common stock, shares authorized	1,500,000,000.0	1,500,000,000.0
Common stock, shares issued	922,000,000	915,000,000
Treasury shares at cost	3,400,000	3,400,000
Alabama Power [Member]
Common stock, par value (in dollars per share)	$ 40	$ 40
Common stock, shares authorized	40,000,000	40,000,000
Common stock, shares outstanding	30,537,500	30,537,500
Georgia Power [Member]
Common stock, no par value (in dollars per share)	$ 0	$ 0
Common stock, shares authorized	20,000,000	20,000,000
Common stock, shares outstanding	9,261,500	9,261,500
Gulf Power [Member]
Common stock, no par value (in dollars per share)	$ 0	$ 0
Common stock, shares authorized	20,000,000	20,000,000
Common stock, shares outstanding	5,642,717	5,642,717
Mississippi Power [Member]
Common stock, no par value (in dollars per share)	$ 0	$ 0
Common stock, shares authorized	1,130,000	1,130,000
Common stock, shares outstanding	1,121,000	1,121,000
Southern Power [Member]
Other intangible assets, accumulated amortization	$ 13	$ 12
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized	1,000,000	1,000,000
Common stock, shares outstanding	1,000	1,000

XML

Introduction

3 Months Ended

Mar. 31, 2016

Organization, Consolidation and Presentation of Financial Statements [Abstract]

INTRODUCTION

INTRODUCTION

The condensed quarterly financial statements of each registrant included herein have been prepared by such registrant, without audit, pursuant to the rules and regulations of the SEC. The Condensed Balance Sheets as of December 31, 2015 have been derived from the audited financial statements of each registrant. In the opinion of each registrant's management, the information regarding such registrant furnished herein reflects all adjustments, which, except as otherwise disclosed, are of a normal recurring nature, necessary to present fairly the results of operations for the periods ended March 31, 2016 and 2015. 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.

Recently Issued Accounting Standards

On February 25, 2016, the FASB issued ASU No. 2016-02, Leases(Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchangedand there is no change to the accounting for existing leveraged leases.ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The registrants are currently evaluating the new standard and have not yet determined its ultimate impact; however, adoption of ASU 2016-02 is expected to have a significant impact on Southern Company and the traditional operating companies' balance sheets.

On March 30, 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation(Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions. Most significantly, entities are required to recognize all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation as income tax expense or benefit in the income statement. Southern Company and the traditional operating companies currently recognize any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation in additional paid-in capital. ASU 2016-09 is effective for fiscal years beginning after December 15, 2016, with early adoption permitted. Southern Company and the traditional operating companies are currently evaluating the new standard and have not yet determined its ultimate impact.

XML

Contingencies and Regulatory Matters

3 Months Ended

Mar. 31, 2016

Commitments and Contingencies Disclosure [Abstract]

CONTINGENCIES AND REGULATORY MATTERS

CONTINGENCIES AND REGULATORY MATTERS

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

General Litigation Matters

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

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

Environmental 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 affected sites. The traditional operating companies have each received authority from their respective state PSCs to recover approved environmental compliance costs through regulatory mechanisms. These rates are adjusted annually or as necessary within limits approved by the state PSCs.

Georgia Power's environmental remediation liability as of March 31, 2016 was $28 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 PRPs at the Brunswick site have completed a removal action as ordered by the EPA. Additional response actions at this site are anticipated. In September 2015, Georgia Power entered into an allocation agreement with another PRP, under which that PRP will be responsible (as between Georgia Power and that PRP) for paying and performing certain investigation, assessment, remediation, and other incidental activities at the Brunswick site. Assessment and potential cleanup of other sites are anticipated.

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.

Gulf Power's environmental remediation liability includes estimated costs of environmental remediation projects of approximately $46 million as of March 31, 2016. These estimated costs primarily relate to site closure criteria by the Florida Department of Environmental Protection (FDEP) for potential impacts to soil and groundwater from herbicide applications at Gulf Power substations. The schedule for completion of the remediation projects is subject to FDEP approval. The projects have been approved by the Florida PSC for recovery through Gulf Power's environmental cost recovery clause; therefore, these liabilities have no impact on net income.

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

FERC Matters

Municipal and Rural Associations Tariff

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

On March 31, 2016, Mississippi Power filed a request with the FERC for an increase in wholesale base revenues as agreed upon in the settlement agreement reached with its wholesale customers under the Municipal and Rural Associations (MRA) cost-based electric tariff. The settlement agreement provides that base rates under the MRA cost-based electric tariff will increase approximately $7 million annually, with revised rates effective for services rendered beginning May 1, 2016. The increase is primarily due to the Plant Daniel Units 1 and 2 scrubbers, which were placed in service in November 2015. Additionally, under the settlement agreement, the tariff customers agreed in principle to similar regulatory treatment for tariff ratemaking as the treatment approved for retail ratemaking under the Mississippi PSC order (In-Service Asset Rate Order). The Kemper IGCC regulatory treatment primarily includes (i) recovery of only the Kemper IGCC assets currently operational and providing service to customers and other related costs and (ii) removing all of the Kemper IGCC CWIP with a corresponding increase in accrual of AFUDC effective May 1, 2016. If approved by the FERC, the amount of base rate revenues to be recognized in 2016 is expected to be approximately $5 million. The additional resulting AFUDC is estimated to be approximately $6 million. The ultimate outcome of this matter cannot be determined at this time.

Fuel Cost Recovery

Mississippi Power has a wholesale MRA and a Market Based (MB) fuel cost recovery factor. At March 31, 2016, the amount of over-recovered wholesale MRA fuel costs included in the balance sheets was $25 million compared to $24 million at December 31, 2015. See Note 3 to the financial statements of Mississippi Power under "FERC Matters – Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information.

Market-Based Rate Authority

The traditional operating companies and Southern Power have authority from the FERC to sell electricity at market-based rates. Since 2008, that authority, for certain balancing authority areas, has been conditioned on compliance with the requirements of an energy auction, which the FERC found to be tailored mitigation that addresses potential market power concerns. In accordance with FERC regulations governing such authority, the traditional operating companies and Southern Power filed a triennial market power analysis in 2014, which included continued reliance on the energy auction as tailored mitigation. In April 2015, the FERC issued an order finding that the traditional operating companies' and Southern Power's existing tailored mitigation may not effectively mitigate the potential to exert market power in certain areas served by the traditional operating companies and in some adjacent areas. The FERC directed the traditional operating companies and Southern Power to show why market-based rate authority should not be revoked in these areas or to provide a mitigation plan to further address market power concerns. The traditional operating companies and Southern Power filed a request for rehearing in May 2015 and in June 2015 filed their response with the FERC. The ultimate outcome of this matter cannot be determined at this time.

Retail Regulatory Matters

Alabama Power

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

Regulatory Clause	Balance Sheet Line Item	March 31, 2016		December 31, 2015
		(in millions)
Rate CNP Compliance	Under recovered regulatory clause revenues, current	$	22	$	43
Rate CNP PPA	Deferred under recovered regulatory clause revenues	105		99
Retail Energy Cost Recovery	Other regulatory liabilities, current	173		238
	Deferred over recovered regulatory clause revenues	64		—
Natural Disaster Reserve	Other regulatory liabilities, deferred	74		75

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.

Georgia Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Georgia PSC. Georgia Power currently recovers its costs from the regulated retail business through the 2013 ARP, which includes traditional base tariff rates, Demand-Side Management tariffs, Environmental Compliance Cost Recovery tariffs, and Municipal Franchise Fee tariffs. In addition, financing costs related to the construction of Plant Vogtle Units 3 and 4 are being collected through the NCCR tariff and fuel costs are collected through separate fuel cost recovery tariffs. See "Fuel Cost Recovery" below and Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Nuclear Construction" and Southern Company under "Retail Regulatory Matters – Georgia Power – Fuel Cost Recovery" and " – Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding fuel cost recovery and the NCCR tariff, respectively.

Pursuant to the terms and conditions of a settlement agreement related to Southern Company's proposed acquisition of AGL Resources approved by the Georgia PSC on April 14, 2016, Georgia Power's 2013 ARP will continue in effect until December 31, 2019, and Georgia Power will be required to file its next base rate case by July 1, 2019. Furthermore, through December 31, 2019, Georgia Power and Atlanta Gas Light Company (collectively, Utilities) will retain the merger savings, net of transition costs, as defined in the settlement agreement; through December 31, 2022, net merger savings will be shared on a 60/40 basis between customers and the Utilities; thereafter, all merger savings will be retained by customers. See Note (I) under "Southern Company – Proposed Merger with AGL Resources" for additional information regarding the Merger.

Fuel Cost Recovery

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

As of March 31, 2016 and December 31, 2015, Georgia Power's over recovered fuel balance totaled $177 million and $116 million, respectively, and is included in current liabilities and other deferred liabilities on Southern Company's and Georgia Power's Condensed Balance Sheets herein. On April 14, 2016, Georgia Power filed a request with the Georgia PSC to decrease fuel rates by 15% effective June 1, 2016, which is expected to reduce annual billings by approximately $313 million. Georgia Power is currently scheduled to file its next fuel case by February 28, 2017. The ultimate outcome of this matter cannot be determined at this time.

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 or Georgia Power's revenues or net income, but will affect cash flow.

Nuclear Construction

See Note 3 to the financial statements of Southern Company and Georgia Power under "Retail Regulatory Matters – Georgia Power – Nuclear Construction" and "Retail Regulatory Matters – Nuclear Construction," respectively, in Item 8 of the Form 10-K for additional information regarding Georgia Power's construction of Plant Vogtle Units 3 and 4, Vogtle Construction Monitoring (VCM) reports, the NCCR tariff, the Vogtle Construction Litigation (as defined below), and the Contractor Settlement Agreement (as defined below).

In 2008, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into an agreement with 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).

Under the terms of the Vogtle 3 and 4 Agreement, the Vogtle Owners agreed to pay a purchase price that is subject to certain price escalations and adjustments, including fixed escalation amounts and index-based adjustments, as well as adjustments for change orders, and performance bonuses for early completion and unit performance. The Vogtle 3 and 4 Agreement also provides for liquidated damages upon the Contractor's failure to fulfill the schedule and performance guarantees, subject to a cap. In addition, the Vogtle 3 and 4 Agreement provides for limited cost sharing by the Vogtle Owners for Contractor costs under certain conditions (which have not occurred), with maximum additional capital costs under this provision attributable to Georgia Power (based on Georgia Power's ownership interest) of approximately $114 million. Each Vogtle Owner is severally (and not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to the Contractor under the Vogtle 3 and 4 Agreement. Georgia Power's proportionate share is 45.7%.

On December 31, 2015, Westinghouse acquired Stone & Webster, Inc. from Chicago Bridge & Iron Company, N.V. (CB&I) and changed the name of Stone & Webster, Inc. to WECTEC Global Project Services Inc. (WECTEC). Certain obligations of Westinghouse and WECTEC under the Vogtle 3 and 4 Agreement were originally guaranteed by Toshiba Corporation (Westinghouse's parent company) and The Shaw Group Inc. (which is now a subsidiary of CB&I), respectively. On March 9, 2016, in connection with Westinghouse's acquisition of WECTEC and pursuant to the settlement agreement described below, the guarantee of The Shaw Group Inc. was terminated. The guarantee of Toshiba Corporation remains in place. 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. Additionally, as a result of credit rating downgrades of Toshiba Corporation, Westinghouse provided the Vogtle Owners with letters of credit in an aggregate amount of $920 million in accordance with, and subject to adjustment under, the terms of the Vogtle 3 and 4 Agreement.

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 Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4. 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 construction capital costs to be borne by Georgia Power increase by 5% above the certified cost 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. In February 2013, Georgia Power 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 (from April 2016) and the fourth quarter 2018 (from April 2017) for Plant Vogtle Units 3 and 4, respectively. In October 2013, the Georgia PSC approved a stipulation (2013 Stipulation) between Georgia Power and the Georgia PSC Staff (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.

On April 15, 2015, the Georgia PSC issued a procedural order in connection with the twelfth VCM report, which included a requested amendment (Requested Amendment) to the Plant Vogtle Units 3 and 4 certificate to reflect the Contractor's revised forecast for completion of Plant Vogtle Units 3 and 4 (second quarter of 2019 and second quarter of 2020, respectively) as well as additional estimated Vogtle Owner's costs, of approximately $10 million per month, including property taxes, oversight costs, compliance costs, and other operational readiness costs to include the estimated Vogtle Owner's costs associated with the proposed 18-month Contractor delay and to increase the estimated total in-service capital cost of Plant Vogtle Units 3 and 4 to $5.0 billion. Pursuant to the Georgia PSC's procedural order, the Georgia PSC deemed the Requested Amendment unnecessary and withdrawn until the completion of construction of Plant Vogtle Unit 3 consistent with the 2013 Stipulation. The Georgia PSC recognized that the certified cost and the 2013 Stipulation do not constitute a cost recovery cap. In accordance with the Georgia Integrated Resource Planning Act, any costs incurred by Georgia Power in excess of the certified amount will be included in rate base, provided Georgia Power shows the costs to be reasonable and prudent. Financing costs up to the certified amount will be collected through the NCCR tariff until the units are placed in service and contemplated in a general base rate case, while financing costs on any construction-related costs in excess of the $4.4 billion certified amount are expected to be recovered through AFUDC.

On December 31, 2015, Westinghouse and the Vogtle Owners entered into a definitive settlement agreement (Contractor Settlement Agreement) to resolve disputes between the Vogtle Owners and the Contractor under the Vogtle 3 and 4 Agreement, including litigation that was pending in the U.S. District Court for the Southern District of Georgia (Vogtle Construction Litigation). Effective December 31, 2015, Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the Contractor entered into an amendment to the Vogtle 3 and 4 Agreement to implement the Contractor Settlement Agreement. The Contractor Settlement Agreement and the related amendment to the Vogtle 3 and 4 Agreement (i) restrict the Contractor's ability to seek further increases in the contract price by clarifying and limiting the circumstances that constitute nuclear regulatory changes in law; (ii) provide for enhanced dispute resolution procedures; (iii) revise the guaranteed substantial completion dates to match the current estimated in-service dates of June 30, 2019 for Unit 3 and June 30, 2020 for Unit 4; (iv) provide that delay liquidated damages will commence from the current estimated nuclear fuel loading date for each unit, which is December 31, 2018 for Unit 3 and December 31, 2019 for Unit 4; and (v) provide that Georgia Power, based on its ownership interest, will pay to the Contractor and capitalize to the project cost approximately $350 million, of which approximately $241 million had been paid as of March 31, 2016. In addition, the Contractor Settlement Agreement provides for the resolution of other open existing items relating to the scope of the project under the Vogtle 3 and 4 Agreement, including cyber security, for which costs were reflected in Georgia Power's previously disclosed in-service cost estimate. Further, as part of the settlement and Westinghouse's acquisition of WECTEC: (i) Westinghouse engaged Fluor Enterprises, Inc., a subsidiary of Fluor Corporation, as a new construction subcontractor; and (ii) the Vogtle Owners, CB&I, and The Shaw Group Inc. entered into mutual releases of any and all claims arising out of events or circumstances in connection with the construction of Plant Vogtle Units 3 and 4 that occurred on or before the date of the Contractor Settlement Agreement. On January 5, 2016, the Vogtle Construction Litigation was dismissed with prejudice.

On January 21, 2016, Georgia Power submitted the Contractor Settlement Agreement and the related amendment to the Vogtle 3 and 4 Agreement to the Georgia PSC for its review. In accordance with the Georgia PSC's subsequent order, on April 5, 2016, Georgia Power filed supplemental information in support of the Contractor Settlement Agreement and Georgia Power's position that all construction costs to date have been prudently incurred and that the current estimated in-service capital cost and schedule are reasonable. The Staff will conduct a review of all costs incurred related to Plant Vogtle Units 3 and 4, the schedule for completion of Plant Vogtle Units 3 and 4, and the Contractor Settlement Agreement and the Staff is authorized to engage in related settlement discussions with Georgia Power and any intervenors.

The order provides that the Staff is required to report to the Georgia PSC by October 19, 2016 with respect to the status of its review and any settlement-related negotiations. If a settlement with the Staff is reached with respect to costs of Plant Vogtle Units 3 and 4, the Georgia PSC will then conduct a hearing to consider whether to approve that settlement. If a settlement with the Staff is not reached, the Georgia PSC will determine how to proceed, including (i) modifying the 2013 Stipulation, (ii) directing Georgia Power to file a request for an amendment to the certificate for Plant Vogtle Units 3 and 4, (iii) issuing a scheduling order to address remaining disputed issues, or (iv) taking any other option within its authority.

The Georgia PSC has approved thirteen VCM reports covering the periods through June 30, 2015, including construction capital costs incurred, which through that date totaled $3.1 billion. On February 26, 2016, Georgia Power filed its fourteenth VCM report with the Georgia PSC covering the period from July 1 through December 31, 2015. The fourteenth VCM report does not include a requested amendment to the certified cost of Plant Vogtle Units 3 and 4. Georgia Power is requesting approval of $160 million of construction capital costs incurred during that period. Georgia Power anticipates to incur average financing costs of approximately $27 million per month from January 2016 until Plant Vogtle Units 3 and 4 are placed in service. The updated in-service capital cost forecast is $5.44 billion and includes costs related to the Contractor Settlement Agreement. Estimated financing costs during the construction period total approximately $2.4 billion. Georgia Power's CWIP balance for Plant Vogtle Units 3 and 4 was approximately $3.7 billion as of March 31, 2016.

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 may arise as construction proceeds. Processes are in place that are designed to assure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating licenses, 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 may 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 challenges with Contractor performance including fabrication, assembly, delivery, and installation of the shield building and structural modules, delays in the receipt of the remaining permits necessary for the operation of Plant Vogtle Units 3 and 4, or other issues could arise and may further impact project schedule and cost. In addition, the IRS allocated production tax credits to each of Plant Vogtle Units 3 and 4, which require the applicable unit to be placed in service before 2021.

Future claims by the Contractor or Georgia Power (on behalf of the Vogtle Owners) could arise throughout construction. These claims may be resolved through formal and informal dispute resolution procedures under the Vogtle 3 and 4 Agreement and, under the enhanced dispute resolution procedures, may be resolved through litigation after the completion of nuclear fuel load for both units.

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

Gulf Power

Retail Base Rate Case

See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Retail Base Rate Case" in Item 8 of the Form 10-K for additional information.

In 2013, the Florida PSC approved a settlement agreement providing that Gulf Power may reduce depreciation and record a regulatory asset up to $62.5 million between January 2014 and June 2017. In any given month, such depreciation reduction may not exceed the amount necessary for the retail ROE, as reported to the Florida PSC monthly, to reach the midpoint of the authorized retail ROE range then in effect. For 2014, 2015, and the first three months of 2016, Gulf Power recognized reductions in depreciation of $8.4 million, $20.1 million, and $5.6 million, respectively.

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 balance of each regulatory clause recovery on the balance sheet follows:

Regulatory Clause	Balance Sheet Location	March 31, 2016		December 31, 2015
		(in millions)
Fuel Cost Recovery	Other regulatory liabilities, current	$	20	$	18
Purchased Power Capacity Recovery	Under recovered regulatory clause revenues	4		1
Environmental Cost Recovery	Under recovered regulatory clause revenues	17		19
Energy Conservation Cost Recovery	Other regulatory liabilities, current	2		4

Mississippi Power

Performance Evaluation Plan

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

On April 1, 2016, Mississippi Power submitted its annual PEP lookback filing for 2015, which reflected the need for a $5 million surcharge to be recovered from customers. The filing has been suspended for review by the Mississippi PSC. The ultimate outcome of this matter 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 retail fuel cost recovery.

At March 31, 2016, the amount of over-recovered retail fuel costs included on Mississippi Power's Condensed Balance Sheet herein was $80 million compared to over-recovered retail fuel costs of $71 million at December 31, 2015.

The Mississippi PSC conditionally approved a decrease of $120 million annually in fuel cost recovery rates on January 5, 2016, effective with the first billing cycle of February. As required by the order, on February 1, 2016, Mississippi Power submitted updated natural gas price forecasts and resulting fuel factors to the Mississippi PSC. If approved by the Mississippi PSC, the updated forecast would decrease fuel cost recovery rates by an additional $36 million annually. The ultimate outcome of this matter cannot be determined at this time.

Integrated Coal Gasification Combined Cycle

See Note 3 to the financial statements of Southern Company and Mississippi Power under "Integrated Coal Gasification Combined Cycle" in Item 8 of the Form 10-K for information regarding Mississippi Power's construction of the Kemper IGCC.

Kemper IGCC Overview

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

Kemper IGCC Schedule and Cost Estimate

In 2012, the Mississippi PSC issued the 2012 MPSC CPCN Order, a detailed order confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing the acquisition, construction, and operation of the Kemper IGCC. The certificated cost estimate of the Kemper IGCC included in the 2012 MPSC CPCN Order was $2.4 billion, net of $245 million of grants awarded to the Kemper IGCC project by the DOE under the Clean Coal Power Initiative Round 2 (Initial DOE Grants) and excluding the cost of the lignite mine and equipment, the cost of the CO₂ pipeline facilities, and AFUDC related to the Kemper IGCC. The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, with recovery of prudently-incurred costs subject to approval by the Mississippi PSC. The Kemper IGCC was originally projected to be placed in service in May 2014. Mississippi Power placed the combined cycle and the associated common facilities portion of the Kemper IGCC in service using natural gas in August 2014 and currently expects to place the remainder of the Kemper IGCC, including the gasifier and the gas clean-up facilities, in service during the third quarter 2016.

Recovery of the costs subject to the cost cap and the cost of the lignite mine and equipment, the cost of the CO₂ pipeline facilities, AFUDC, and certain general exceptions, including change of law, force majeure, and beneficial capital (which exists when Mississippi Power demonstrates that the purpose and effect of the construction cost increase is to produce efficiencies that will result in a neutral or favorable effect on customers relative to the original proposal for the CPCN) (Cost Cap Exceptions) remains subject to review and approval by the Mississippi PSC. Mississippi Power's Kemper IGCC 2010 project estimate, current cost estimate (which includes the impacts of the Mississippi Supreme Court's (Court) decision discussed herein under "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order"), and actual costs incurred as of March 31, 2016, are as follows:

Cost Category	2010 Project Estimate(f)		Current Cost Estimate(a)			Actual Costs
	(in billions)
Plant Subject to Cost Cap(b)(g)	$	2.40	$	5.35		$	4.99
Lignite Mine and Equipment	0.21		0.23			0.23
CO2 Pipeline Facilities	0.14		0.11			0.12
AFUDC(c)	0.17		0.71			0.62
Combined Cycle and Related Assets Placed in Service – Incremental(d)(g)	—		0.02			0.01
General Exceptions	0.05		0.10			0.09
Deferred Costs(e)(g)	—		0.20			0.18
Additional DOE Grants(h)	—		(0.14		)	—
Total Kemper IGCC	$	2.97	$	6.58		$	6.24

(a) Amounts in the Current Cost Estimate reflect estimated costs through September 30, 2016.

(b) The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, net of the Initial DOE Grants and excluding the Cost Cap Exceptions. The Current Cost Estimate and the Actual Costs include non-incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service in August 2014 that are subject to the $2.88 billion cost cap and exclude post-in-service costs for the lignite mine. See "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" herein for additional information. The Current Cost Estimate and the Actual Costs reflect 100% of the costs of the Kemper IGCC. See note (g) for additional information.

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

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

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

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

(g) Beginning in the third quarter 2015, certain costs, including debt carrying costs (associated with assets placed in service and other non-CWIP accounts), that previously were deferred as regulatory assets are now being recognized through income; however, such costs continue to be included in the Current Cost Estimate and the Actual Costs at March 31, 2016.

(h) On April 8, 2016, Mississippi Power received approximately $137 million in additional grants from the DOE for the Kemper IGCC, which are expected to be used to reduce future rate impacts for customers.

Of the total costs, including post-in-service costs for the lignite mine, incurred as of March 31, 2016, $3.61 billion was included in property, plant, and equipment (which is net of the Initial DOE Grants and estimated probable losses of $2.47 billion), $6 million in other property and investments, $75 million in fossil fuel stock, $45 million in materials and supplies, $22 million in other regulatory assets, current, $196 million in other regulatory assets, deferred, $1 million in other current assets, and $11 million in other deferred charges and assets in the balance sheet.

Mississippi Power does not intend to seek rate recovery for any costs related to the construction of the Kemper IGCC that exceed the $2.88 billion cost cap, net of the Initial DOE Grants and excluding the Cost Cap Exceptions. Mississippi Power recorded pre-tax charges to income for revisions to the cost estimate above the cost cap of $53 million ($33 million after tax) in the first quarter 2016. Since 2012, in the aggregate, Mississippi Power has incurred charges of $2.47 billion ($1.52 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through March 31, 2016. The increase to the cost estimate in the first quarter 2016 primarily reflects costs for the extension of the Kemper IGCC's projected in-service date through September 30, 2016, and increased efforts related to operational readiness and challenges in start-up and commissioning activities which includes the cost of repairs and modifications to the refractory lining inside the gasifiers. Any extension of the in-service date beyond September 30, 2016 is currently estimated to result in additional base costs of approximately $25 million to $35 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. However, additional costs may be required for remediation of any further equipment and/or design issues identified. Any extension of the in-service date with respect to the Kemper IGCC beyond September 30, 2016 would also increase costs for the Cost Cap Exceptions, which are not subject to the $2.88 billion cost cap established by the Mississippi PSC. These costs include AFUDC, which is currently estimated to total approximately $14 million per month, as well as carrying costs and operating expenses on Kemper IGCC assets placed in service and consulting and legal fees of approximately $2 million per month. For additional information, see "2015 Rate Case" herein.

Mississippi Power's analysis of the time needed to complete the start-up and commissioning activities for the Kemper IGCC will continue until the remaining Kemper IGCC assets are placed in service. 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 operating or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities for this first-of-a-kind technology (including major equipment failure and system integration), and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC). In subsequent periods, any further changes in the estimated costs to complete construction and start-up of the Kemper IGCC subject to the $2.88 billion cost cap, net of the Initial DOE Grants and excluding the Cost Cap Exceptions, will be reflected in Southern Company's and Mississippi Power's statements of income and these changes could be material.

Rate Recovery of Kemper IGCC Costs

See "FERC Matters" herein for additional information regarding Mississippi Power's MRA cost based tariff relating to recovery of a portion of the Kemper IGCC costs from Mississippi Power's wholesale customers. Rate recovery of the retail portion of the Kemper IGCC is subject to the jurisdiction of the Mississippi PSC. See Note (G) under "Unrecognized Tax Benefits – Section 174 Research and Experimental Deduction" for additional tax information related to the Kemper IGCC.

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 future proceedings related to the operation of the Kemper IGCC. To the extent the Mississippi PSC determines the Kemper IGCC does not meet the operational parameters ultimately adopted by the Mississippi PSC or Mississippi Power incurs additional costs to satisfy such parameters, there could be a material adverse impact on Southern Company's or Mississippi Power's financial statements.

2013 MPSC Rate Order

In January 2013, Mississippi Power entered into a settlement agreement with the Mississippi PSC that was intended to establish the process for resolving matters regarding cost recovery related to the Kemper IGCC (2013 Settlement Agreement). Under the 2013 Settlement Agreement, Mississippi Power agreed to limit the portion of prudently-incurred Kemper IGCC costs to be included in retail rate base to the $2.4 billion certificated cost estimate, plus the Cost Cap Exceptions, but excluding AFUDC, and any other costs permitted or determined to be excluded from the $2.88 billion cost cap by the Mississippi PSC. In March 2013, the Mississippi PSC issued a rate order approving retail rate increases of 15% effective March 19, 2013 and 3% effective January 1, 2014, which collectively were designed to collect $156 million annually beginning in 2014 (2013 MPSC Rate Order) to be used to mitigate customer rate impacts after the Kemper IGCC is placed in service, based on a mirror CWIP methodology (Mirror CWIP rate).

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. 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.

On February 12, 2015, the Court reversed the 2013 MPSC Rate Order based on, among other things, its findings that (1) the Mirror CWIP rate treatment was not provided for under the Baseload Act and (2) the Mississippi PSC should have determined the prudence of Kemper IGCC costs before approving rate recovery through the 2013 MPSC Rate Order. The Court also found the 2013 Settlement Agreement unenforceable due to a lack of public notice for the related proceedings. On July 7, 2015, the Mississippi PSC ordered that the Mirror CWIP rate be terminated effective July 20, 2015 and required the fourth quarter 2015 refund of the $342 million collected under the 2013 MPSC Rate Order, along with associated carrying costs of $29 million. The Court's decision did not impact the 2012 MPSC CPCN Order or the February 2013 legislation described below.

2015 Rate Case

As a result of the 2015 Court decision, on July 10, 2015, Mississippi Power filed a supplemental filing including a request for interim rates (Supplemental Notice) with the Mississippi PSC which presented an alternative rate proposal (In-Service Asset Proposal) designed to recover Mississippi Power's costs associated with the Kemper IGCC assets that are commercially operational and currently providing service to customers (the transmission facilities, combined cycle, natural gas pipeline, and water pipeline) and other related costs. On August 13, 2015, the Mississippi PSC approved the implementation of the requested interim rates designed to collect approximately $159 million annually effective with the first billing cycle in September 2015, subject to refund and certain other conditions.

On December 3, 2015, the Mississippi PSC issued the In-Service Asset Rate Order adopting in full a stipulation entered into between Mississippi Power and the Mississippi Public Utilities Staff (MPUS) regarding the In-Service Asset Proposal. The In-Service Asset Rate Order provided for retail rate recovery of an annual revenue requirement of approximately $126 million, based on Mississippi Power's actual average capital structure, with a maximum common equity percentage of 49.733%, a 9.225% return on common equity, and actual embedded interest costs. The In-Service Asset Rate Order also included a prudence finding of all costs in the stipulated revenue requirement calculation for the in-service assets. The stipulated revenue requirement excluded the costs of the Kemper IGCC related to the 15% undivided interest that was previously projected to be purchased by SMEPA. Mississippi Power continues to evaluate its alternatives with respect to its investment and related costs associated with the 15% undivided interest.

With implementation of the new rate on December 17, 2015, the interim rates were terminated and, in March 2016, Mississippi Power completed customer refunds of approximately $11 million for the difference between the interim rates collected and the permanent rates.

Pursuant to the In-Service Asset Rate Order, Mississippi Power is required to file a subsequent rate request within 18 months. As part of the filing, Mississippi Power expects to request recovery of certain costs that the Mississippi PSC had excluded from the revenue requirement calculation.

On February 25, 2016, Greenleaf CO2 Solutions, LLC filed a notice of appeal of the In-Service Asset Rate Order with the Court. On May 5, 2016, the Court dismissed the appeal.

Legislation to authorize a multi-year rate plan and legislation to provide for alternate financing through securitization of up to $1.0 billion of prudently-incurred costs was enacted into law in 2013. Mississippi Power expects to securitize prudently-incurred qualifying facility costs in excess of the certificated cost estimate of $2.4 billion. Qualifying facility costs include, but are not limited to, pre-construction costs, construction costs, regulatory costs, and accrued AFUDC. The Court's decision regarding the 2013 MPSC Rate Order did not impact Mississippi Power's ability to utilize alternate financing through securitization or the February 2013 legislation.

Mississippi Power expects to seek additional rate relief to address recovery of the remaining Kemper IGCC assets. In addition to current estimated costs at March 31, 2016 of $6.58 billion, Mississippi Power anticipates that it will incur additional costs after the Kemper IGCC in-service date until the Kemper IGCC cost recovery approach is finalized. These costs include, but are not limited to, regulatory costs and additional carrying costs which could be material. Recovery of these costs would be subject to approval by the Mississippi PSC.

Regulatory Assets and Liabilities

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

In August 2014, Mississippi Power requested confirmation by the Mississippi PSC of Mississippi Power's authority to defer all operating expenses associated with the operation of the combined cycle subject to review of such costs by the Mississippi PSC. In addition, Mississippi Power is authorized to accrue carrying costs on the unamortized balance of such regulatory assets at a rate and in a manner to be determined by the Mississippi PSC in future cost recovery mechanism proceedings. Beginning in the third quarter 2015, in connection with the implementation of interim rates, Mississippi Power began expensing certain ongoing project costs and certain debt carrying costs (associated with assets placed in service and other non-CWIP accounts) that previously were deferred as regulatory assets and began amortizing certain regulatory assets associated with assets placed in service and consulting and legal fees. The amortization periods for these regulatory assets vary from two years to 10 years as set forth in the In-Service Asset Rate Order. As of March 31, 2016, the balance associated with these regulatory assets was $120 million, of which $22 million is included in current assets. Other regulatory assets associated with the remainder of the Kemper IGCC totaled $98 million as of March 31, 2016. The amortization period for these assets is expected to be determined by the Mississippi PSC in future rate proceedings following completion of construction and start-up of the Kemper IGCC and related prudence reviews.

See "2013 MPSC Rate Order" herein for information related to the July 7, 2015 Mississippi PSC order terminating the Mirror CWIP rate and requiring refund of collections under Mirror CWIP.

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

The In-Service Asset Rate Order requires Mississippi Power to submit an annual true-up calculation of its actual cost of capital, compared to the stipulated total cost of capital, with the first occurring as of May 31, 2016. As of March 31, 2016, Mississippi Power recorded a related regulatory liability of approximately $3 million. See "2015 Rate Case" herein for additional information.

Lignite Mine and CO₂ Pipeline Facilities

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

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

In addition, Mississippi Power has constructed and will operate the CO₂ pipeline for the planned transport of captured CO₂ for use in enhanced oil recovery. Mississippi Power has entered into agreements with Denbury Onshore (Denbury), a subsidiary of Denbury Resources Inc., and Treetop Midstream Services, LLC (Treetop), an affiliate of Tellus Operating Group, LLC and a subsidiary of Tengrys, LLC, pursuant to which Denbury will purchase 70% of the CO₂ captured from the Kemper IGCC and Treetop will purchase 30% of the CO₂ captured from the Kemper IGCC. The agreements with Denbury and Treetop provide Denbury and Treetop with termination rights as Mississippi Power has not satisfied its contractual obligation to deliver captured CO₂ by May 11, 2015. Since May 11, 2015, Mississippi Power has been engaged in ongoing discussions with its off-takers regarding the status of the CO₂ delivery schedule as well as other issues related to the CO₂ agreements. As a result of discussions with Treetop, on August 3, 2015, Mississippi Power agreed to amend certain provisions of their agreement that do not affect pricing or minimum purchase quantities. Potential requirements imposed on CO₂ off-takers under the Clean Power Plan (if ultimately enacted in its current form, pending resolution of litigation) and the potential adverse financial impact of low oil prices on the off-takers increase the risk that the CO₂ contracts may be terminated or materially modified. Any termination or material modification of these agreements could result in a material reduction in Mississippi Power's revenues to the extent Mississippi Power is not able to enter into other similar contractual arrangements. Additionally, if the contracts remain in place, sustained oil price reductions could result in significantly lower revenues than Mississippi Power forecasted to be available to offset customer rate impacts, which could have a material impact on Mississippi Power's financial statements.

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

Civil Lawsuit

On April 26, 2016, a complaint against Mississippi Power was filed in Harrison County Circuit Court by Biloxi Freezing & Processing Inc., Gulfside Casino Partnership, and John Carlton Dean. The plaintiffs allege that Mississippi Power violated the Mississippi Unfair Trade Practices Act and concealed, falsely represented, and failed to fully disclose important facts concerning the cost and schedule of the Kemper IGCC and that Mississippi Power's alleged breaches interfered with and destroyed economically advantageous relationships between the plaintiffs and their current and prospective business associates. The plaintiffs seek unspecified actual damages and punitive damages as well as attorney's fees, costs, and interest. The plaintiffs also seek an injunction to prevent any Kemper IGCC costs from being charged to customers through electric rates. Mississippi Power believes this legal challenge has no merit; however, an adverse outcome in this proceeding could impact Southern Company's results of operations, financial condition, and liquidity and could have a material impact on Mississippi Power's results of operations, financial condition, and liquidity. Mississippi Power will vigorously defend the matter, and the final outcome of this matter cannot be determined at this time.

XML

Fair Value Measurements

3 Months Ended

Mar. 31, 2016

Fair Value Disclosures [Abstract]

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS

As of March 31, 2016, assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows:

	Fair Value Measurements Using
As of March 31, 2016:	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Net Asset Value as a Practical Expedient (NAV)		Total
	(in millions)
Southern Company
Assets:
Energy-related derivatives	$	—	$	12	$	—	$	—	$	12
Interest rate derivatives	—		33		—		—		33
Nuclear decommissioning trusts(a)	624		898		—		16		1,538
Cash equivalents	503		—		—		—		503
Other investments	9		—		1		—		10
Total	$	1,136	$	943	$	1	$	16	$	2,096
Liabilities:
Energy-related derivatives	$	—	$	201	$	—	$	—	$	201
Interest rate derivatives	—		193		—		—		193
Total	$	—	$	394	$	—	$	—	$	394
Alabama Power
Assets:
Energy-related derivatives	$	—	$	3	$	—	$	—	$	3
Nuclear decommissioning trusts(b)
Domestic equity	365		67		—		—		432
Foreign equity	46		48		—		—		94
U.S. Treasury and government agency securities	—		25		—		—		25
Corporate bonds	11		137		—		—		148
Mortgage and asset backed securities	—		21		—		—		21
Private Equity	—		—		—		16		16
Other	—		9		—		—		9
Cash equivalents	321		—		—		—		321
Total	$	743	$	310	$	—	$	16	$	1,069
Liabilities:
Energy-related derivatives	$	—	$	49	$	—	$	—	$	49

	Fair Value Measurements Using
As of March 31, 2016:	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Net Asset Value as a Practical Expedient (NAV)		Total
	(in millions)
Georgia Power
Assets:
Energy-related derivatives	$	—	$	4	$	—	$	—	$	4
Interest rate derivatives	—		14		—		—		14
Nuclear decommissioning trusts(b) (c)
Domestic equity	180		1		—		—		181
Foreign equity	—		115		—		—		115
U.S. Treasury and government agency securities	—		111		—		—		111
Municipal bonds	—		66		—		—		66
Corporate bonds	—		146		—		—		146
Mortgage and asset backed securities	—		145		—		—		145
Other	22		7		—		—		29
Cash equivalents	57		—		—		—		57
Total	$	259	$	609	$	—	$	—	$	868
Liabilities:
Energy-related derivatives	$	—	$	11	$	—	$	—	$	11
Gulf Power
Assets:
Cash equivalents	$	20	$	—	$	—	$	—	$	20
Liabilities:
Energy-related derivatives	$	—	$	94	$	—	$	—	$	94
Interest rate derivatives	—		5		—		—		5
Total	$	—	$	99	$	—	$	—	$	99
Mississippi Power
Assets:
Cash equivalents	$	24	$	—	$	—	$	—	$	24
Liabilities:
Energy-related derivatives	$	—	$	44	$	—	$	—	$	44
Southern Power
Assets:
Energy-related derivatives	$	—	$	5	$	—	$	—	$	5
Interest rate derivatives	—		1		—		—		1
Cash equivalents	39		—		—		—		39
Total	$	39	$	6	$	—	$	—	$	45
Liabilities:
Energy-related derivatives	$	—	$	3	$	—	$	—	$	3

(a) For additional detail, see the nuclear decommissioning trusts sections for Alabama Power and Georgia Power in this table.

(b) Excludes receivables related to investment income, pending investment sales, payables related to pending investment purchases, and currencies.

(c) Includes the investment securities pledged to creditors and collateral received and excludes payables related to the securities lending program. As of March 31, 2016, approximately $58 million of the fair market value of Georgia Power's nuclear decommissioning trust funds' securities were on loan to creditors under the funds' managers' securities lending program.

Southern Company, Alabama Power, and Georgia Power continue to elect the option to fair value investment securities held in the nuclear decommissioning trust funds. For the three months ended March 31, 2016 and March 31, 2015, the change in fair value of the funds, including reinvested interest and dividends and excluding the funds' expenses, increased by $20 million and $33 million, respectively, at Southern Company. For the three months ended March 31, 2016 and March 31, 2015, Alabama Power recorded an increase in fair value of $11 million and $15 million, respectively, as an increase in regulatory liabilities related to its asset retirement obligations. For the three months ended March 31, 2016 and March 31, 2015, Georgia Power recorded an increase in fair value of $9 million and $18 million, respectively, as a reduction of its regulatory asset related to its asset retirement obligations.

Valuation Methodologies

The energy-related derivatives primarily consist of over-the-counter financial products for natural gas and physical power products, including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and overnight index swap interest rates. Interest rate derivatives are also standard over-the-counter products that are valued using observable market data and assumptions commonly used by market participants. The fair value of interest rate derivatives reflect the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future interest rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk, and occasionally, implied volatility of interest rate options. The interest rate derivatives are categorized as Level 2 under Fair Value Measurements as these inputs are based on observable data and valuations of similar instruments. See Note (H) for additional information on how these derivatives are used.

The NRC requires licensees of commissioned nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. For fair value measurements of the investments within the nuclear decommissioning trusts, external pricing vendors are designated for each asset class with each security specifically assigned a primary pricing source. For investments held within commingled funds, fair value is determined at the end of each business day through the net asset value, which is established by obtaining the underlying securities' individual prices from the primary pricing source. A market price secured from the primary source vendor is then evaluated by management in its valuation of the assets within the trusts. As a general approach, fixed income market pricing vendors gather market data (including indices and market research reports) and integrate relative credit information, observed market movements, and sector news into proprietary pricing models, pricing systems, and mathematical tools. Dealer quotes and other market information, including live trading levels and pricing analysts' judgments, are also obtained when available. See Note 1 to the financial statements of Southern Company, Alabama Power, and Georgia Power under "Nuclear Decommissioning" in Item 8 of the Form 10-K for additional information.

"Other investments" include investments that are not traded in the open market. The fair value of these investments have been determined based on market factors including comparable multiples and the expectations regarding cash flows and business plan executions.

As of March 31, 2016, the fair value measurements of private equity investments held in the nuclear decommissioning trust that are calculated at net asset value per share (or its equivalent) as a practical expedient, as well as the nature and risks of those investments, were as follows:

As of March 31, 2016:	Fair Value		Unfunded Commitments		Redemption Frequency	Redemption Notice Period
	(in millions)
Southern Company	$	16	$	29	Not Applicable	Not Applicable
Alabama Power	$	16	$	29	Not Applicable	Not Applicable

Private equity funds include a fund-of-funds that invests in high-quality private equity funds across several market sectors, a fund that invests in real estate assets, and a fund that acquires companies to create resale value. Private equity funds do not have redemption rights. Distributions from these funds will be received as the underlying investments in the funds are liquidated. Liquidations are expected to occur at various times over the next ten years.

As of March 31, 2016, 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, including securities due within one year:
Southern Company	$	28,341	$	29,827
Alabama Power	$	7,089	$	7,688
Georgia Power	$	10,549	$	11,400
Gulf Power	$	1,303	$	1,366
Mississippi Power	$	3,209	$	2,938
Southern Power	$	3,123	$	3,171

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 available to the registrants.

XML

Stockholders' Equity

3 Months Ended

Mar. 31, 2016

Equity [Abstract]

STOCKHOLDERS' EQUITY

STOCKHOLDERS' EQUITY

Earnings per Share

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

	Three Months Ended March 31, 2016	Three Months Ended March 31, 2015
	(in millions)
As reported shares	916	910
Effect of options and performance share award units	6	5
Diluted shares	922	915

Stock options and performance share award units that were not included in the diluted earnings per share calculation because they were anti-dilutive were immaterial for the three months ended March 31, 2016 and 2015.

Changes in Stockholders' Equity

The following table presents year-to-date changes in stockholders' equity of Southern Company:

	Number of Common Shares			Common Stockholders' Equity			Preferred and Preference Stock of Subsidiaries					Total Stockholders' Equity
	Issued	Treasury							Noncontrolling Interests(*)
	(in thousands)			(in millions)
Balance at December 31, 2015	915,073	(3,352	)	$	20,592		$	609	$	781		$	21,982
Consolidated net income attributable to Southern Company	—	—		485			—		—			485
Other comprehensive income (loss)	—	—		(114		)	—		—			(114		)
Stock issued	6,572	—		270			—		—			270
Stock-based compensation	—	—		60			—		—			60
Cash dividends on common stock	—	—		(497		)	—		—			(497		)
Contributions from noncontrolling interests	—	—		—			—		129			129
Distributions to noncontrolling interests	—	—		—			—		(4		)	(4		)
Purchase of membership interests from noncontrolling interests	—	—		—			—		(129		)	(129		)
Net income attributable to noncontrolling interests	—	—		—			—		1			1
Other	—	(35	)	1			—		—			1
Balance at March 31, 2016	921,645	(3,387	)	$	20,797		$	609	$	778		$	22,184
Balance at December 31, 2014	908,502	(725	)	$	19,949		$	756	$	221		$	20,926
Consolidated net income attributable to Southern Company	—	—		508			—		—			508
Other comprehensive income (loss)	—	—		(15		)	—		—			(15		)
Stock issued	3,094	—		112			—		—			112
Stock-based compensation	—	—		53			—		—			53
Stock repurchased, at cost	—	(2,599	)	(115		)	—		—			(115		)
Cash dividends on common stock	—	—		(478		)	—		—			(478		)
Other	—	(11	)	3			—		—			3
Balance at March 31, 2015	911,596	(3,335	)	$	20,017		$	756	$	221		$	20,994

(*) Primarily related to Southern Power Company.

XML

Financing

3 Months Ended

Mar. 31, 2016

Debt Disclosure [Abstract]

FINANCING

FINANCING

Bank Credit Arrangements

Bank credit arrangements provide liquidity support to the registrants' commercial paper borrowings and the traditional operating companies' pollution control revenue bonds. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of March 31, 2016 was approximately $1.8 billion (comprised of approximately $810 million at Alabama Power, $868 million at Georgia Power, $82 million at Gulf Power, and $40 million at Mississippi Power). In addition, at March 31, 2016, the traditional operating companies had approximately $269 million (comprised of approximately $167 million at Alabama Power, $69 million at Georgia Power, and $33 million at Gulf Power) of fixed rate pollution control revenue bonds outstanding that were required to be reoffered 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. See "Financing Activities" herein for additional information.

The following table outlines the committed credit arrangements by company as of March 31, 2016:

	Expires											Executable Term Loans				Due Within One Year
Company	2016		2017		2018		2020	Total		Unused		One Year		Two Years		Term Out		No Term Out
								(in millions)				(in millions)				(in millions)
Southern Company (a)	$	—	$	—	$	1,000	$1,250	$	2,250	$	2,250	$	—	$	—	$	—	$	—
Alabama Power	40		—		500		800	1,340		1,340		—		—		—		40
Georgia Power	—		—		—		1,750	1,750		1,732		—		—		—		—
Gulf Power	75		40		165		—	280		280		45		—		45		40
Mississippi Power	205		—		—		—	205		180		30		15		45		160
Southern Power Company (b)	—		—		—		600	600		560		—		—		—		—
Other	70		—		—		—	70		70		20		—		20		50
Total	$	390	$	40	$	1,665	$4,400	$	6,495	$	6,412	$	95	$	15	$	110	$	290

(a) Excludes the $8.1 billion Bridge Agreement entered into in September 2015 that will be funded only to the extent necessary to provide financing for the Merger as discussed herein.

(b) Excluding its subsidiaries. See "Project Credit Facilities" below and Note (I) under "Southern Power" for additional information.

Subject to applicable market conditions, Southern Company and its subsidiaries expect to renew or replace their bank credit arrangements as needed, prior to expiration. In connection therewith, Southern Company and its subsidiaries may extend the maturity dates and/or increase or decrease the lending commitments thereunder.

Southern Company intends to fund the cash consideration for the Merger using a mix of debt and equity. Southern Company finances its capital needs on a portfolio basis and expects to issue a minimum of $8.0 billion in debt prior to closing the Merger and a minimum of $1.2 billion in equity during 2016. This capital is expected to provide funding for the Merger, the proposed acquisition of PowerSecure International, Inc. (PowerSecure), and Southern Power and other Southern Company system capital projects. Total capital raised in 2016 may increase due to cash needed at the closing of the Merger, settlement of hedges, and incremental investment opportunities, including additional Southern Power projects in excess of its current capital plans. In addition, Southern Company entered into the $8.1 billion Bridge Agreement on September 30, 2015 to provide financing for the Merger in the event long-term financing is not available. As of March 31, 2016, Southern Company had no outstanding loans under the Bridge Agreement. See Note (I) under "Southern Company – Proposed Merger with AGL Resources" for additional information regarding the Merger. See Note 6 to the financial statements of Southern Company under "Bank Credit Arrangements" in Item 8 of the Form 10-K for additional information regarding the Bridge Agreement.

Southern Power Project Credit Facilities

In connection with the construction of solar facilities by RE Tranquillity LLC, RE Roserock LLC, and RE Garland Holdings LLC, indirect subsidiaries of Southern Power, each subsidiary entered into separate credit agreements (Project Credit Facilities), which are non-recourse to Southern Power (other than the subsidiary party to the agreement). Each Project Credit Facility provides (a) a senior secured construction loan credit facility, (b) a senior secured bridge loan facility, and (c) a senior secured letter of credit facility that is secured by the membership interests of the respective project company. Proceeds from the Project Credit Facilities are being used to finance project costs related to the respective solar facilities currently under construction. Each Project Credit Facility is secured by the assets of the applicable project subsidiary and membership interests of the applicable project subsidiary. The table below summarizes each Project Credit Facility as of March 31, 2016.

Project	Maturity Date	Construction Loan Facility		Bridge Loan Facility		Total		Total Undrawn		Letter of Credit Facility		Total Undrawn
		(in millions)
Tranquillity	Earlier of COD or December 31, 2016	$	86	$	172	$	258	$	52	$	77	$	26
Roserock	Earlier of COD or November 30, 2016	63		180		243		121		23		16
Garland	Earlier of COD or November 30, 2016	86		308		394		309		49		32
Total		$	235	$	660	$	895	$	482	$	149	$	74

The Project Credit Facilities had total amounts outstanding as of March 31, 2016 of $413 million at a weighted average interest rate of 1.99%. For the three months ended March 31, 2016, these credit agreements had a maximum amount outstanding of $413 million, and an average amount outstanding of $260 million at a weighted average interest rate of 1.99%.

Financing Activities

The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first three months of 2016:

Company(a)	Senior Note Issuances		Senior Note Maturities and Redemptions		Revenue Bond Maturities Redemptions and Repurchases		Other Long-Term Debt Issuances			Other Long-Term Debt Redemptions and Maturities(b)
	(in millions)
Alabama Power	$	400	$	200	$	—	$	45		$	—
Georgia Power	650		250		4		—			1
Mississippi Power	—		—		—		1,100			426
Southern Power	—		—		—		2			3
Other	—		—		—		—			4
Elimination(c)	—		—		—		(200		)	—
Total	$	1,050	$	450	$	4	$	947		$	434

(a) Southern Company and Gulf Power did not issue or redeem any long-term debt during the first three months of 2016.    

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

(c) Intercompany loans from Southern Company to Mississippi Power eliminated in Southern Company's Consolidated Financial Statements.

Alabama Power

In January 2016, Alabama Power issued $400 million aggregate principal amount of Series 2016A 4.30% Senior Notes due January 2, 2046. The proceeds were used to repay at maturity $200 million aggregate principal amount of Alabama Power's Series FF 5.20% Senior Notes due January 15, 2016 and for general corporate purposes, including Alabama Power's continuous construction program.

In March 2016, Alabama Power entered into three bank term loan agreements with maturity dates of March 2021, in an aggregate principal amount of $45 million, one of which bears interest at 2.38% per annum and two of which bear interest based on three-month LIBOR.

Georgia Power

In March 2016, Georgia Power issued $325 million aggregate principal amount of Series 2016A 3.25% Senior Notes due April 1, 2026 and $325 million aggregate principal amount of Series 2016B 2.40% Senior Notes due April 1, 2021. An amount equal to the proceeds from the Series 2016A 3.25% Senior Notes due April 1, 2026 will be allocated to eligible green expenditures, including financing of or investments in solar power generation facilities or electric vehicle charging infrastructure, or payments under PPAs served by solar power or wind generation facilities. The proceeds from the Series 2016B 2.40% Senior Notes due April 1, 2021 were used to repay at maturity $250 million aggregate principal amount of Georgia Power's Series 2013B Floating Rate Senior Notes due March 15, 2016, to repay a portion of Georgia Power's short-term indebtedness, and for general corporate purposes, including Georgia Power's continuous construction program.

Mississippi Power

In January 2016, Mississippi Power issued a floating rate promissory note to Southern Company in an aggregate principal amount of up to $275 million, which matures on December 1, 2017, bearing interest based on one-month LIBOR. As of March 31, 2016, Mississippi Power had borrowed $100 million under this promissory note with a $50 million draw occurring on each of January 29, 2016 and March 14, 2016. In addition, on January 19, 2016, Mississippi Power borrowed $100 million from Southern Company pursuant to a promissory note issued in November 2015.

On March 8, 2016, Mississippi Power entered into an unsecured term loan agreement for an aggregate amount of $1.2 billion to repay existing indebtedness and for other general corporate purposes. Mississippi Power borrowed $900 million under the term loan agreement and has the right to borrow the remaining $300 million on or before October 15, 2016, upon satisfaction of certain customary conditions. Mississippi Power used the initial proceeds to repay $900 million in maturing bank notes on March 8, 2016 and expects the remaining $300 million to be used to repay senior notes maturing in October 2016. The term loan pursuant to this agreement matures on April 1, 2018 and bears interest based on one-month LIBOR.

Also in March 2016, Mississippi Power renewed a $10 million short-term note, which matures on June 30, 2016, bearing interest based on three-month LIBOR.

Southern Power

During the three months ended March 31, 2016, Southern Power's subsidiary repaid $3 million of long-term debt payable to Turner Renewable Energy, LLC (TRE) and borrowed $2 million due February 28, 2036 under promissory notes payable to TRE.

During the three months ended March 31, 2016, Southern Power's subsidiaries borrowed $276 million pursuant to the Project Credit Facilities at a weighted average interest rate of 1.99%. In addition, Southern Power's subsidiaries issued $8 million in letters of credit.

XML

Retirement Benefits

3 Months Ended

Mar. 31, 2016

Compensation and Retirement Disclosure [Abstract]

RETIREMENT BENEFITS

RETIREMENT BENEFITS

Southern Company has a defined benefit, trusteed, pension plan covering substantially all employees. The qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended. No mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 2016. Southern Company also provides certain defined benefit pension plans for a selected group of management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. In addition, Southern Company provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The traditional operating companies fund related other postretirement trusts to the extent required by their respective regulatory commissions.

See Note 2 to the financial statements of Southern Company, Alabama Power, Georgia Power, Gulf Power, and Mississippi Power in Item 8 of the Form 10-K for additional information.

Components of the net periodic benefit costs for the three months ended March 31, 2016 were as follows:

Pension Plans	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power
	(in millions)
Three Months Ended March 31, 2016
Service cost	$	62		$	14		$	17		$	3		$	3
Interest cost	100			24			34			5			5
Expected return on plan assets	(187		)	(46		)	(64		)	(9		)	(9		)
Amortization:
Prior service costs	4			1			1			—			—
Net (gain)/loss	38			10			14			2			2
Net cost	$	17		$	3		$	2		$	1		$	1
Three Months Ended March 31, 2015
Service cost	$	64		$	15		$	18		$	3		$	3
Interest cost	111			26			38			5			5
Expected return on plan assets	(181		)	(45		)	(63		)	(8		)	(8		)
Amortization:
Prior service costs	6			2			3			—			—
Net (gain)/loss	54			14			19			3			3
Net cost	$	54		$	12		$	15		$	3		$	3

Postretirement Benefits	Southern Company			Alabama Power			Georgia Power			Gulf Power		Mississippi Power
	(in millions)
Three Months Ended March 31, 2016
Service cost	$	5		$	1		$	2		$	—	$	—
Interest cost	18			5			8			1		1
Expected return on plan assets	(14		)	(6		)	(6		)	—		—
Amortization:
Prior service costs	2			1			—			—		—
Net (gain)/loss	3			—			2			—		—
Net cost	$	14		$	1		$	6		$	1	$	1
Three Months Ended March 31, 2015
Service cost	$	6		$	1		$	2		$	—	$	—
Interest cost	19			5			8			1		1
Expected return on plan assets	(15		)	(6		)	(6		)	—		—
Amortization:
Prior service costs	1			1			—			—		—
Net (gain)/loss	5			—			3			—		—
Net cost	$	16		$	1		$	7		$	1	$	1

XML

Income Taxes

3 Months Ended

Mar. 31, 2016

Income Tax Disclosure [Abstract]

INCOME TAXES

INCOME TAXES

Current and Deferred Income Taxes

Southern Power ITC Carryforwards

As of March 31, 2016, Southern Power had federal ITC carryforwards which are expected to result in $694 million of federal income tax benefits compared to $551 million as of December 31, 2015. The carryforwards as of March 31, 2016 begin expiring in 2034 but are expected to be utilized by the end of 2021.

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 employee stock plans' dividend deduction, non-taxable AFUDC equity, and federal income tax benefits from ITCs and PTCs.

Southern Company's effective tax rate was 30.8% for the three months ended March 31, 2016 compared to 34.3% for the corresponding period in 2015. The effective tax rate decrease was primarily due to increased federal income tax benefits from ITCs and PTCs and lower pre-tax earnings in 2016.

Mississippi Power

Mississippi Power's effective tax rate was (838.7)% for the three months ended March 31, 2016 compared to 10.0% for the corresponding period in 2015. The effective tax rate decrease was primarily due to an increase in tax benefits related to the estimated probable losses on construction of the Kemper IGCC.

Southern Power

Southern Power's effective tax rate was (84.0)% for the three months ended March 31, 2016 compared to 25.8% for the corresponding period in 2015. The effective tax rate decrease was primarily due to increased federal income tax benefits from ITCs related to solar projects expected to be placed in service in 2016 and additional PTCs related to wind projects in 2016 compared to 2015.

Unrecognized Tax Benefits

See Note 5 to the financial statements of each registrant under "Unrecognized Tax Benefits" in Item 8 of the Form 10-K for additional information.

Changes during 2016 for unrecognized tax benefits were as follows:

	Mississippi Power		Southern Power		Southern Company
	(in millions)
Unrecognized tax benefits as of December 31, 2015	$	421	$	8	$	433
Tax positions from current periods	—		5		5
Balance as of March 31, 2016	$	421	$	13	$	438

The tax positions from current periods primarily relate to federal income tax benefits from ITCs.

The impact on the effective tax rate, if recognized, is as follows:

	As of March 31, 2016							As of December 31, 2015
	Mississippi Power			Southern Power		Southern Company		Southern Company
	(in millions)
Tax positions impacting the effective tax rate	$	(2	)	$	13	$	15	$	10
Tax positions not impacting the effective tax rate	423			—		423		423
Balance of unrecognized tax benefits	$	421		$	13	$	438	$	433

The tax positions impacting the effective tax rate primarily relate to federal income tax benefits from ITCs. The tax positions not impacting the effective tax rate relate to deductions for Kemper IGCC-related research and experimental (R&E) expenditures. See "Section 174 Research and Experimental Deduction" below for additional information. These amounts are presented on a gross basis without considering the related federal or state income tax impact.

Accrued interest for unrecognized tax benefits was immaterial for all periods presented.

All of the registrants classify interest on tax uncertainties as interest expense. None of the registrants accrued any penalties on uncertain tax positions.

It is reasonably possible that the amount of the unrecognized tax benefits could change within 12 months. The settlement of federal and state audits could impact the balances significantly. At this time, an estimate of the range of reasonably possible outcomes cannot be determined.

The IRS has finalized its audits of Southern Company's consolidated federal income tax returns through 2012. Southern Company has filed its 2013 and 2014 federal income tax returns and has received partial acceptance letters from the IRS; however, the IRS has not finalized its audits. Southern Company is a participant in the Compliance Assurance Process of the IRS. The audits for the Southern Company's state income tax returns have either been concluded, or the statute of limitations has expired, for years prior to 2011.

Section 174 Research and Experimental Deduction

Southern Company has reflected deductions for R&E expenditures related to the Kemper IGCC in its federal income tax calculations since 2013 and has filed amended federal income tax returns for 2008 through 2013 to also include such deductions.

The Kemper IGCC is based on first-of-a-kind technology, and Southern Company and Mississippi Power believe that a significant portion of the plant costs qualify as deductible R&E expenditures 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, Southern Company and Mississippi Power had related unrecognized tax benefits associated with these R&E deductions of approximately $423 million and associated interest of $12 million as of March 31, 2016. The ultimate outcome of this matter cannot be determined at this time.

XML

Derivatives

3 Months Ended

Mar. 31, 2016

Derivative Instruments and Hedging Activities Disclosure [Abstract]

DERIVATIVES

DERIVATIVES

Southern Company, the traditional operating companies, and Southern Power are exposed to market risks, primarily commodity price risk and interest rate risk. To manage the volatility attributable to these exposures, each company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to each company's policies in areas such as counterparty exposure and risk management practices. Each company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a gross basis. See Note (C) for additional information. In the statements of cash flows, the cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities.

Energy-Related Derivatives

The traditional operating companies and Southern Power enter into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the traditional operating companies have limited exposure to market volatility in commodity fuel prices and prices of electricity. Each of the traditional operating companies manages fuel-hedging programs, implemented per the guidelines of their respective state PSCs, through the use of financial derivative contracts, which is expected to continue to mitigate price volatility. The traditional operating companies (with respect to wholesale generating capacity) and Southern Power have limited exposure to market volatility in commodity fuel prices and prices of electricity because their long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, the traditional operating companies and Southern Power may be exposed to market volatility in energy-related commodity prices to the extent any uncontracted wholesale generating capacity is used to sell electricity.

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) are initially deferred in OCI before being recognized in the statements of income in the same period as the hedged transactions are reflected in earnings.

• Not Designated — Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.

Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric industry. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered.

At March 31, 2016, 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	235	2020	2017
Alabama Power	60	2019	—
Georgia Power	65	2019	—
Gulf Power	74	2020	—
Mississippi Power	28	2018	—
Southern Power	8	2016	2017

In addition to the volumes discussed in the above table, the traditional operating companies and Southern Power enter into physical natural gas supply contracts that provide the option to sell back excess gas due to operational constraints. The maximum expected volume of natural gas subject to such a feature is 4 million mmBtu for Southern Company and Georgia Power.

For cash flow hedges, the amounts expected to be reclassified from accumulated OCI to earnings for the next 12-month period ending March 31, 2017 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. Fair value gains or losses on derivatives that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.

At March 31, 2016, the following interest rate derivatives were outstanding:

	Notional Amount			Interest Rate Received	Weighted Average Interest Rate Paid	Hedge Maturity Date		Fair Value Gain (Loss) at March 31, 2016
	(in millions)							(in millions)
Cash Flow Hedges of Forecasted Debt
Southern Company	$	1,500		3-month LIBOR	2.14%	November 2026		$	(55	)
Southern Company	1,200			3-month LIBOR	2.60%	November 2046		(127		)
Gulf Power	80			3-month LIBOR	2.32%	December 2026		(4		)
Cash Flow Hedges of Existing Debt
Georgia Power	200			3-month LIBOR + 0.40%	1.01%	August 2016		—
Fair Value Hedges on Existing Debt
Southern Company	250			1.30%	3-month LIBOR + 0.17%	August 2017		1
Southern Company	300			2.75%	3-month LIBOR + 0.92%	June 2020		10
Georgia Power	250			5.40%	3-month LIBOR + 4.02%	June 2018		3
Georgia Power	200			4.25%	3-month LIBOR + 2.46%	December 2019		6
Georgia Power	500			1.95%	3-month LIBOR + 0.76%	December 2018		5
Derivatives not Designated as Hedges
Southern Power	65		(a,d)	3-month LIBOR	2.50%	October 2016	(e)	—
Southern Power	47		(b,d)	3-month LIBOR	2.21%	October 2016	(e)	—
Southern Power	65		(c,d)	3-month LIBOR	2.21%	November 2016	(f)	—
Total	$	4,657						$	(161	)

(a) Swaption at RE Tranquillity LLC. See Note 12 to the financial statements of Southern Company and Note 2 to the financial statements of Southern Power in Item 8 of the Form 10-K for additional information.

(b) Swaption at RE Roserock LLC. See Note 12 to the financial statements of Southern Company and Note 2 to the financial statements of Southern Power in Item 8 of the Form 10-K for additional information.

(c) Swaption at RE Garland Holdings LLC. See Note 12 to the financial statements of Southern Company and Note 2 to the financial statements of Southern Power in Item 8 of the Form 10-K for additional information.

(d) Amortizing notional amount.

(e) Represents the mandatory settlement date. Settlement will be based on a 15-year amortizing swap.

(f) Represents the mandatory settlement date. Settlement will be based on a 12-year amortizing swap.

The estimated pre-tax gains (losses) that will be reclassified from accumulated OCI to interest expense for the next 12-month period ending March 31, 2017 are immaterial for all registrants. Southern Company and certain subsidiaries have deferred gains and losses that are expected to be amortized into earnings through 2046.

Derivative Financial Statement Presentation and Amounts

At March 31, 2016, the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows:

Asset Derivatives at March 31, 2016
	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	$	2	$	1	$	1	$	—	$	—
Other deferred charges and assets	5		2		3		—		—
Total derivatives designated as hedging instruments for regulatory purposes	$	7	$	3	$	4	$	—	$	—	N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Other current assets(*)	$	4	$	—	$	—	$	—	$	—	$	4
Interest rate derivatives:
Other current assets	18		—		7		—		—		—
Other deferred charges and assets	14		—		7		—		—		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	36	$	—	$	14	$	—	$	—	$	4
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets(*)	$	1	$	—	$	—	$	—	$	—	$	1
Interest rate derivatives:
Other current assets(*)	1		—		—		—		—		1
Total derivatives not designated as hedging instruments	$	2	$	—	$	—	$	—	$	—	$	2
Total asset derivatives	$	45	$	3	$	18	$	—	$	—	$	6

(*) Southern Power includes current assets related to derivatives in "Assets from risk management activities."

Liability Derivatives at March 31, 2016
	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(*)	$	124	$	37	$	9	$	49	$	29
Other deferred credits and liabilities	74		12		2		45		15
Total derivatives designated as hedging instruments for regulatory purposes	$	198	$	49	$	11	$	94	$	44	N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Liabilities from risk management activities(*)	$	2	$	—	$	—	$	—	$	—	$	2
Interest rate derivatives:
Liabilities from risk management activities(*)	193		—		—		5		—		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	195	$	—	$	—	$	5	$	—	$	2
Derivatives not designated as hedging instruments
Energy-related derivatives:
Liabilities from risk management activities(*)	$	1	$	—	$	—	$	—	$	—	$	1
Total liability derivatives	$	394	$	49	$	11	$	99	$	44	$	3

(*) Georgia Power, Mississippi Power, and Southern Power include current liabilities related to derivatives in "Other current liabilities."

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

Asset Derivatives at December 31, 2015
	Fair Value
Derivative Category and Balance Sheet Location	Southern Company		Alabama Power		Georgia Power		Gulf Power		Mississippi Power		Southern Power
	(in millions)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets	$	3	$	1	$	2	$	—	$	—	N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Other current assets(*)	$	3	$	—	$	—	$	—	$	—	$	3
Interest rate derivatives:
Other current assets	19		—		5		1		—		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	22	$	—	$	5	$	1	$	—	$	3
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets(*)	$	1	$	—	$	—	$	—	$	—	$	1
Interest rate derivatives:
Other current assets(*)	3		—		—		—		—		3
Total derivatives not designated as hedging instruments	$	4	$	—	$	—	$	—	$	—	$	4
Total asset derivatives	$	29	$	1	$	7	$	1	$	—	$	7

(*) Southern Power includes current assets related to derivatives in "Assets from risk management activities."

Liability Derivatives at December 31, 2015
	Fair Value
Derivative Category and Balance Sheet Location	Southern Company		Alabama Power		Georgia Power		Gulf Power		Mississippi Power		Southern Power
	(in millions)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Liabilities from risk management activities(*)	$	130	$	40	$	12	$	49	$	29
Other deferred credits and liabilities	87		15		3		51		18
Total derivatives designated as hedging instruments for regulatory purposes	$	217	$	55	$	15	$	100	$	47	N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Liabilities from risk management activities(*)	$	2	$	—	$	—	$	—	$	—	$	2
Interest rate derivatives:
Liabilities from risk management activities	23		15		—		—		—		—
Other deferred credits and liabilities	7		—		6		—		—		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	32	$	15	$	6	$	—	$	—	$	2
Derivatives not designated as hedging instruments
Energy-related derivatives:
Liabilities from risk management activities(*)	$	1	$	—	$	—	$	—	$	—	$	1
Total liability derivatives	$	250	$	70	$	21	$	100	$	47	$	3

(*) Georgia Power, Mississippi Power, and Southern Power include current liabilities related to derivatives 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 and interest rate derivative contracts at March 31, 2016 and December 31, 2015 are presented in the following tables.

Derivative Contracts at March 31, 2016
	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		$	3		$	4		$	—	$	—	$	5
Gross amounts not offset in the Balance Sheet (b)	(10		)	(3		)	(3		)	—		—		(2		)
Net energy-related derivative assets	$	2		$	—		$	1		$	—	$	—	$	3
Interest rate derivatives:
Interest rate derivatives presented in the Balance Sheet (a)	$	33		$	—		$	14		$	—	$	—	$	1
Gross amounts not offset in the Balance Sheet (b)	(21		)	—			—			—		—		—
Net interest rate derivative assets	$	12		$	—		$	14		$	—	$	—	$	1
Liabilities
Energy-related derivatives:
Energy-related derivatives presented in the Balance Sheet (a)	$	201		$	49		$	11		$	94	$	44	$	3
Gross amounts not offset in the Balance Sheet (b)	(10		)	(3		)	(3		)	—		—		(2		)
Net energy-related derivative liabilities	$	191		$	46		$	8		$	94	$	44	$	1
Interest rate derivatives:
Interest rate derivatives presented in the Balance Sheet (a)	$	193		$	—		$	—		$	5	$	—	$	—
Gross amounts not offset in the Balance Sheet (b)	(21		)	—			—			—		—		—
Net interest rate derivative liabilities	$	172		$	—		$	—		$	5	$	—	$	—

(a) None of the registrants offsets fair value amounts for multiple derivative instruments executed with the same counterparty on the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented on the balance sheets are the same.

(b) Includes gross amounts subject to netting terms that are not offset on the balance sheets and any cash/financial collateral pledged or received.

Derivative Contracts at December 31, 2015
	Fair Value
	Southern Company			Alabama Power			Georgia Power			Gulf Power		Mississippi Power		Southern Power
	(in millions)
Assets
Energy-related derivatives:
Energy-related derivatives presented in the Balance Sheet (a)	$	7		$	1		$	2		$	—	$	—	$	4
Gross amounts not offset in the Balance Sheet (b)	(6		)	(1		)	(2		)	—		—		(1		)
Net energy-related derivative assets	$	1		$	—		$	—		$	—	$	—	$	3
Interest rate derivatives:
Interest rate derivatives presented in the Balance Sheet (a)	$	22		$	—		$	5		$	1	$	—	$	4
Gross amounts not offset in the Balance Sheet (b)	(9		)	—			(4		)	—		—		—
Net interest rate derivative assets	$	13		$	—		$	1		$	1	$	—	$	4
Liabilities
Energy-related derivatives:
Energy-related derivatives presented in the Balance Sheet (a)	$	220		$	55		$	15		$	100	$	47	$	3
Gross amounts not offset in the Balance Sheet (b)	(6		)	(1		)	(2		)	—		—		(1		)
Net energy-related derivative liabilities	$	214		$	54		$	13		$	100	$	47	$	2
Interest rate derivatives:
Interest rate derivatives presented in the Balance Sheet (a)	$	30		$	15		$	6		$	—	$	—	$	—
Gross amounts not offset in the Balance Sheet (b)	(9		)	—			(4		)	—		—		—
Net interest rate derivative liabilities	$	21		$	15		$	2		$	—	$	—	$	—

(a) None of the registrants offsets fair value amounts for multiple derivative instruments executed with the same counterparty on the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented on the balance sheets are the same.

(b) Includes gross amounts subject to netting terms that are not offset on the balance sheets and any cash/financial collateral pledged or received.

At March 31, 2016 and December 31, 2015, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred were as follows:

Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet at March 31, 2016
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	$	(124	)	$	(37	)	$	(9	)	$	(49	)	$	(29	)
Other regulatory assets, deferred	(74		)	(12		)	(2		)	(45		)	(15		)
Other regulatory liabilities, current (a)	2			1			1			—			—
Other regulatory liabilities, deferred (b)	5			2			3			—			—
Total energy-related derivative gains (losses)	$	(191	)	$	(46	)	$	(7	)	$	(94	)	$	(44	)

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

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

Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet at December 31, 2015
Derivative Category and Balance Sheet Location	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power
	(in millions)
Energy-related derivatives:
Other regulatory assets, current	$	(130	)	$	(40	)	$	(12	)	$	(49	)	$	(29	)
Other regulatory assets, deferred	(87		)	(15		)	(3		)	(51		)	(18		)
Other regulatory liabilities, current(*)	3			1			2			—			—
Total energy-related derivative gains (losses)	$	(214	)	$	(54	)	$	(13	)	$	(100	)	$	(47	)

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

For the three months ended March 31, 2016 and 2015, the pre-tax effects of interest rate derivatives designated as cash flow hedging instruments were as follows:

Derivatives in Cash Flow Hedging Relationships	Gain (Loss) Recognized in OCI on Derivative (Effective Portion)						Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)
							Statements of Income Location	Amount
	2016			2015				2016			2015
	(in millions)							(in millions)
Southern Company
Interest rate derivatives	$	(190	)	$	(29	)	Interest expense, net of amounts capitalized	$	(3	)	$	(2	)
Alabama Power
Interest rate derivatives	$	(4	)	$	(6	)	Interest expense, net of amounts capitalized	$	(1	)	$	(1	)
Georgia Power
Interest rate derivatives	$	—		$	(23	)	Interest expense, net of amounts capitalized	$	(1	)	$	(1	)
Gulf Power
Interest rate derivatives	$	(5	)	$	—		Interest expense, net of amounts capitalized	$	—		$	—

For the three months ended March 31, 2016 and 2015, the pre-tax effects of energy-related derivatives designated as cash flow hedging instruments recognized in OCI and those reclassified from accumulated OCI into earnings were immaterial for all registrants.

For the three months ended March 31, 2016 and 2015, the pre-tax effects of interest rate derivatives designated as fair value hedging instruments were as follows:

Derivatives in Fair Value Hedging Relationships
		Gain (Loss)
Derivative Category	Statements of Income Location	2016		2015
		(in millions)
Southern Company
Interest rate derivatives:	Interest expense, net of amounts capitalized	$	20	$	7
Georgia Power
Interest rate derivatives:	Interest expense, net of amounts capitalized	$	14	$	6

For the three months ended March 31, 2016 and 2015, the pre-tax effects of interest rate derivatives designated as fair value hedging instruments were offset by changes to the carrying value of long-term debt. There was no material ineffectiveness recorded in earnings for any registrant for any period presented.

For the three months ended March 31, 2016 and 2015, the pre-tax effects of energy-related derivatives and interest rate derivatives not designated as hedging instruments were immaterial for all registrants.

Contingent Features

The registrants do not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain Southern Company subsidiaries. At March 31, 2016, the registrants' collateral posted with their derivative counterparties was immaterial.

At March 31, 2016, the fair value of derivative liabilities with contingent features was $49 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 $49 million and include certain agreements that could require collateral in the event that one or more Southern Company power pool participants has a credit rating change to below investment grade.

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

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

XML

Acquisitions

3 Months Ended

Mar. 31, 2016

Business Combinations [Abstract]

ACQUISITIONS

ACQUISITIONS

Southern Company

Proposed Merger with AGL Resources

On August 23, 2015, Southern Company entered into the Merger Agreement to acquire AGL Resources. Under the terms of the Merger Agreement, subject to the satisfaction or waiver (if permissible under applicable law) of specified conditions, Merger Sub will be merged with and into AGL Resources. AGL Resources will survive the Merger and become a wholly-owned, direct subsidiary of Southern Company.

The Merger will be accounted for using the acquisition method of accounting whereby the assets acquired and liabilities assumed are recognized at fair value as of the acquisition date. The excess of the purchase price over the fair values of AGL Resources' assets and liabilities will be recorded as goodwill. Southern Company expects total cash of $8.2 billion to be required to fund the purchase price of approximately $8.0 billion to acquire AGL Resources common stock, options to purchase shares of AGL Resources common stock, and restricted stock units payable in shares of AGL Resources common stock and to fund acquisition-related expenses and financing costs of approximately $200 million. Southern Company will also assume AGL Resources' outstanding indebtedness.

Through May 5, 2016, the Maryland PSC, the Georgia PSC, the California Public Utilities Commission, and the Virginia State Corporation Commission have approved the Merger. On April 15, 2016, Southern Company, AGL Resources, and Northern Illinois Gas Company (collectively, the Joint Applicants) and the Retail Energy Supply Association filed a settlement agreement with the Illinois Commerce Commission. On April 28, 2016, the Joint Applicants, the Illinois Attorney General's Office, and the Citizens Utility Board filed a settlement agreement with the Illinois Commerce Commission. Collectively, these agreements resolve all remaining contested issues for Illinois Commerce Commission approval of the Merger. On May 5, 2016, Southern Company, AGL Resources, Merger Sub, Pivotal Utility Holdings, Inc. d/b/a Elizabethtown Gas, the Division of Rate Counsel, the Staff of the New Jersey Board of Public Utilities, and New Jersey Large Energy Users Coalition entered into a comprehensive settlement agreement relating to the New Jersey Board of Public Utilities review of the Merger. Additionally, the Federal Communications Commission (FCC) has approved the transfer of control over the FCC licenses of certain AGL Resources subsidiaries. Consummation of the Merger remains subject to the satisfaction or waiver of certain closing conditions, including, among others, (i) the approval of the Illinois Commerce Commission and the New Jersey Board of Public Utilities and other approvals required under applicable state laws, (ii) the absence of a judgment, order, decision, injunction, ruling, or other finding or agency requirement of a governmental entity prohibiting the consummation of the Merger, and (iii) other customary closing conditions, including (a) subject to certain materiality qualifiers, the accuracy of each party's representations and warranties and (b) each party's performance in all material respects of its obligations under the Merger Agreement.

During the first quarter 2016, Southern Company recorded in its statements of income external transaction costs for financing, legal, and consulting services associated with the proposed Merger of approximately $20 million, of which $6 million is included in operating expenses and $14 million is included in other income and (expense).

The ultimate outcome of these matters cannot be determined at this time. See Note 12 to the financial statements of Southern Company under "Southern Company – Proposed Merger with AGL Resources" in Item 8 of the Form 10-K for additional information.

Merger Financing

Southern Company intends to fund the cash consideration for the Merger using a mix of debt and equity. Southern Company expects to issue the debt to fund the cash consideration for the Merger in several tranches including long-dated maturities. The amount of debt issued at each maturity will depend on prevailing market conditions at the time of the offering and other factors. In addition, Southern Company entered into the $8.1 billion Bridge Agreement on September 30, 2015 to provide financing for the Merger in the event long-term financing is not available. See Note 6 to the financial statements of Southern Company under "Bank Credit Arrangements" in Item 8 of the Form 10-K for additional information regarding the Bridge Agreement.

Proposed Acquisition of PowerSecure

On February 24, 2016, Southern Company entered into an Agreement and Plan of Merger to acquire PowerSecure. Under the terms of this merger agreement, the stockholders of PowerSecure will be entitled to receive $18.75 in cash for each share of common stock in a transaction with a total purchase price of approximately $431 million. Following this transaction, PowerSecure will become a wholly-owned subsidiary of Southern Company. This transaction is expected to close in May 2016. The ultimate outcome of this matter cannot be determined at this time.

Southern Power

See Note 2 to the financial statements of Southern Power and Note 12 to the financial statements of Southern Company under "Southern Power" in Item 8 of the Form 10-K for additional information. During the first quarter 2016, the fair values of the assets and liabilities acquired of Lost Hills, Blackwell, North Star, and Morelos were finalized and there were no changes.

During 2016, in accordance with its overall growth strategy, Southern Power acquired or contracted to acquire through its wholly-owned subsidiaries, Southern Renewable Partnerships, LLC or Southern Renewable Energy, Inc., the projects set forth in the following table. Acquisition-related costs were expensed as incurred and were not material. The acquisitions do not include any contingent consideration unless specifically noted.

Project Facility	Seller; Acquisition Date	Approx. Nameplate Capacity	Location	Southern Power Percentage Ownership		Expected/Actual COD	PPA Counterparties for Plant Output	PPA Contract Period	Approx. Purchase Price
		(MW)							(in millions)
SOLAR
Calipatria	Solar Frontier Americas Holding, LLC February 11, 2016	20	Imperial County, CA	90	%	February 11, 2016	San Diego Gas & Electric Company	20 years	$	51	(a)
East Pecos	First Solar, Inc. March 4, 2016	120	Pecos County, TX	100	%	Fourth quarter 2016	Austin Energy	15 years	$	41	(b)
WIND
Grant Wind	Apex Clean Energy Holdings, LLC April 7, 2016	151	Grant County, OK	100	%	April 8, 2016	Western Farmers, East Texas, and Northeast Texas Electric Cooperative	20 years	$	258	(c)
Passadumkeag	Quantam Wind Acquisition I, LLC	40	Penobscot County, ME	100	%	Second quarter 2016	Western Massachusetts Electric Company	15 years	$	127	(d)

(a) Calipatria - The total purchase price, including the minority owner, TRE's 10% ownership interest and contingent consideration of $6 million, is approximately $57 million. As of March 31, 2016, the fair values of the assets and liabilities acquired through the business combination were recorded as follows: $58 million as property, plant, and equipment, $1 million as a transmission interconnection prepaid, and $2 million as payables; however, the allocation of the purchase price to individual assets has not been finalized.

(b) East Pecos - The total purchase price is approximately $41 million. As of March 31, 2016, the fair values of the assets acquired through the business combination were recorded as $41 million to CWIP; however, the allocation of the purchase price to individual assets has not been finalized. Total construction costs, which include the acquisition price allocated to CWIP, are expected to be approximately $200 million to $220 million. The ultimate outcome of this matter cannot be determined at this time.

(c) Grant Wind - Subsequent to March 31, 2016, Southern Power acquired all of the outstanding membership interests of Grant Wind, LLC. The purchase price includes approximately $23 million of contingent consideration which may be adjusted based on performance testing and production over the first 10 years of operation.

(d) Passadumkeag - On March 11, 2016, Southern Power entered into an agreement to acquire all of the outstanding membership interests of Quantum Wind Acquisition I, LLC, which is expected to close in the second quarter 2016. The ultimate outcome of this matter cannot be determined at this time.

Construction Projects

During the first quarter 2016, in accordance with its overall growth strategy, Southern Power completed construction of and placed in service the Butler Solar Farm and Pawpaw solar facilities. In addition, Southern Power continued construction of the projects set forth in the table below. Through March 31, 2016, total costs of construction incurred for the projects below were $2.2 billion, of which $1.5 billion remains in CWIP. The ultimate outcome of these matters cannot be determined at this time.

Solar Facility	Seller	Approx. Nameplate Capacity	Location	Expected/Actual COD	PPA Counterparties for Plant Output	PPA Contract Period	Estimated Construction Costs
		(MW)					(in millions)
Butler	CERSM, LLC and Community Energy, Inc.	103	Taylor County, GA	Fourth quarter 2016	Georgia Power(a)	30 years	$	220	-	230	(b)
Desert Stateline	First Solar, Inc.	299(c)	San Bernardino County, CA	Through third quarter 2016	Southern California Edison Company (SCE)	20 years	$	1,200	-	1,300	(d)
Garland and Garland A	Recurrent Energy, LLC	205	Kern County, CA	Fourth quarter 2016   Third quarter 2016	SCE	15 years and 20 years	$	532	-	552	(e,f)
Roserock	Recurrent Energy, LLC	160	Pecos County, TX	Fourth quarter 2016	Austin Energy	20 years	$	333	-	353	(e,f)
Sandhills	N/A	146	Taylor County, GA	Fourth quarter 2016	Cobb, Flint, Irwin, Middle Georgia and Sawnee Electric Membership Corporations	25 years	$	260	-	280
Tranquillity	Recurrent Energy, LLC	205	Fresno County, CA	Third quarter 2016	Shell Energy North America (US), LP/SCE	18 years	$	473	-	493	(f,g)

(a) Butler - Affiliate PPA subject to FERC approval.

(b) Butler - Total estimated construction costs include the acquisition price of all outstanding membership interests of the related entity.

(c) Desert Stateline - The facility has a total of 299 MWs, of which 110 MWs were placed in service in the fourth quarter 2015 and 76 MWs were placed in service in the first quarter 2016. Subsequent to March 31, 2016, 38 MWs were placed in service. The remaining 75 MWs are expected to be placed in service by the end of the third quarter 2016.

(d) Desert Stateline - On March 29, 2016, Southern Power acquired an additional 15% interest in Desert Stateline. As a result, Southern Power and the class B member are entitled to 66% and 34%, respectively, of all cash distributions from Desert Stateline. In addition, Southern Power will continue to be entitled to substantially all of the federal tax benefits with respect to the transaction. Total estimated construction costs include the acquisition price allocated to CWIP; however, the allocation of the purchase price to individual assets has not been finalized.

(e) Total estimated construction costs include the acquisition price allocated to CWIP. During the first quarter 2016, the allocation of the purchase price to individual assets was finalized with no changes.

(f) Southern Power owns 100% of the class A membership interests and a wholly-owned subsidiary of the seller owns 100% of the class B membership interests. Southern Power and the class B member are entitled to 51% and 49%, respectively, of all cash distributions from the project.

(g) Total estimated construction costs include the acquisition price allocated to CWIP; however, the allocation of the purchase price to individual assets has not been finalized.

XML

Segment and Related Information

3 Months Ended

Mar. 31, 2016

Segment Reporting [Abstract]

SEGMENT AND RELATED INFORMATION

SEGMENT AND RELATED INFORMATION

The primary business of the Southern Company system is electricity sales by the traditional operating companies and Southern Power. The four traditional operating companies – Alabama Power, Georgia Power, Gulf Power, and Mississippi Power – are vertically integrated utilities providing electric service in four Southeastern states. Southern Power constructs, acquires, owns, and manages generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market.

Southern Company's reportable business segments are the sale of electricity by the four traditional operating companies and Southern Power. Revenues from sales by Southern Power to the traditional operating companies were $97 million and $114 million for the three months ended March 31, 2016 and March 31, 2015, respectively. The "All Other" column includes parent Southern Company, which does not allocate operating expenses to business segments. Also, this category includes segments below the quantitative threshold for separate disclosure. These segments include investments in telecommunications and leveraged lease projects. All other inter-segment revenues are not material.

Financial data for business segments and products and services for the three months ended March 31, 2016 and 2015 was as follows:

	Electric Utilities
	Traditional Operating Companies		Southern Power		Eliminations			Total		All Other			Eliminations			Consolidated
	(in millions)
Three Months Ended March 31, 2016:
Operating revenues	$	3,742	$	315	$	(103	)	$	3,954	$	47		$	(36	)	$	3,965
Segment net income (loss)(a)(b)	464		50		—			514		(26		)	(3		)	485
Total assets at March 31, 2016	$	69,240	$	8,999	$	(396	)	$	77,843	$	2,070		$	(1,178	)	$	78,735
Three Months Ended March 31, 2015:
Operating revenues	$	3,948	$	348	$	(124	)	$	4,172	$	40		$	(29	)	$	4,183
Segment net income (loss)(a)(b)	477		33		—			510		3			(5		)	508
Total assets at December 31, 2015	$	69,052	$	8,905	$	(397	)	$	77,560	$	1,819		$	(1,061	)	$	78,318

(a) Attributable to Southern Company.

(b) Segment net income (loss) for the traditional operating companies includes pre-tax charges for estimated probable losses on the Kemper IGCC of $53 million ($33 million after tax) and $9 million ($6 million after tax) for the three months ended March 31, 2016 and 2015, respectively. See Note (B) under "Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" for additional information.

Products and Services

	Electric Utilities' Revenues
Period	Retail		Wholesale		Other		Total
	(in millions)
Three Months Ended March 31, 2016	$	3,377	$	396	$	181	$	3,954
Three Months Ended March 31, 2015	3,542		467		163		4,172

XML

Introduction (Policies)

3 Months Ended

Mar. 31, 2016

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of Accounting

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, 2015 have been derived from the audited financial statements of each registrant. In the opinion of each registrant's management, the information regarding such registrant furnished herein reflects all adjustments, which, except as otherwise disclosed, are of a normal recurring nature, necessary to present fairly the results of operations for the periods ended March 31, 2016 and 2015. 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.

Reclassification

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

Recently Issued Accounting Standards

Recently Issued Accounting Standards

On February 25, 2016, the FASB issued ASU No. 2016-02, Leases(Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchangedand there is no change to the accounting for existing leveraged leases.ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The registrants are currently evaluating the new standard and have not yet determined its ultimate impact; however, adoption of ASU 2016-02 is expected to have a significant impact on Southern Company and the traditional operating companies' balance sheets.

On March 30, 2016, the FASB issued ASU No. 2016-09, Compensation-Stock Compensation(Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 changes the accounting for income taxes and the cash flow presentation for share-based payment award transactions. Most significantly, entities are required to recognize all excess tax benefits and deficiencies related to the exercise or vesting of stock compensation as income tax expense or benefit in the income statement. Southern Company and the traditional operating companies currently recognize any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation in additional paid-in capital. ASU 2016-09 is effective for fiscal years beginning after December 15, 2016, with early adoption permitted. Southern Company and the traditional operating companies are currently evaluating the new standard and have not yet determined its ultimate impact.

Valuation Methodologies

Valuation Methodologies

The energy-related derivatives primarily consist of over-the-counter financial products for natural gas and physical power products, including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and overnight index swap interest rates. Interest rate derivatives are also standard over-the-counter products that are valued using observable market data and assumptions commonly used by market participants. The fair value of interest rate derivatives reflect the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future interest rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk, and occasionally, implied volatility of interest rate options. The interest rate derivatives are categorized as Level 2 under Fair Value Measurements as these inputs are based on observable data and valuations of similar instruments. See Note (H) for additional information on how these derivatives are used.

The NRC requires licensees of commissioned nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. For fair value measurements of the investments within the nuclear decommissioning trusts, external pricing vendors are designated for each asset class with each security specifically assigned a primary pricing source. For investments held within commingled funds, fair value is determined at the end of each business day through the net asset value, which is established by obtaining the underlying securities' individual prices from the primary pricing source. A market price secured from the primary source vendor is then evaluated by management in its valuation of the assets within the trusts. As a general approach, fixed income market pricing vendors gather market data (including indices and market research reports) and integrate relative credit information, observed market movements, and sector news into proprietary pricing models, pricing systems, and mathematical tools. Dealer quotes and other market information, including live trading levels and pricing analysts' judgments, are also obtained when available. See Note 1 to the financial statements of Southern Company, Alabama Power, and Georgia Power under "Nuclear Decommissioning" in Item 8 of the Form 10-K for additional information.

"Other investments" include investments that are not traded in the open market. The fair value of these investments have been determined based on market factors including comparable multiples and the expectations regarding cash flows and business plan executions.

Earnings per Share

Earnings per Share

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

Energy-Related Derivatives and Interest Rate Derivatives

Energy-Related Derivatives

The traditional operating companies and Southern Power enter into energy-related derivatives to hedge exposures to electricity, gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the traditional operating companies have limited exposure to market volatility in commodity fuel prices and prices of electricity. Each of the traditional operating companies manages fuel-hedging programs, implemented per the guidelines of their respective state PSCs, through the use of financial derivative contracts, which is expected to continue to mitigate price volatility. The traditional operating companies (with respect to wholesale generating capacity) and Southern Power have limited exposure to market volatility in commodity fuel prices and prices of electricity because their long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, the traditional operating companies and Southern Power may be exposed to market volatility in energy-related commodity prices to the extent any uncontracted wholesale generating capacity is used to sell electricity.

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) are initially deferred in OCI before being recognized in the statements of income in the same period as the hedged transactions are reflected in earnings.

• Not Designated — Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.

Some energy-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the electric industry. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered.

Interest Rate Derivatives

Southern Company and certain subsidiaries may also enter into interest rate derivatives to hedge exposure to changes in interest rates. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow hedges where the effective portion of the derivatives' fair value gains or losses is recorded in OCI and is reclassified into earnings at the same time the hedged transactions affect earnings, with any ineffectiveness recorded directly to earnings. Derivatives related to existing fixed rate securities are accounted for as fair value hedges, where the derivatives' fair value gains or losses and hedged items' fair value gains or losses are both recorded directly to earnings, providing an offset, with any difference representing ineffectiveness. Fair value gains or losses on derivatives that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.

XML

Contingencies and Regulatory Matters (Tables)

3 Months Ended

Mar. 31, 2016

Commitments and Contingencies Disclosure [Abstract]

Recovery Balance of Each Regulatory Clause

The balance of each regulatory clause recovery on the balance sheet follows:

Regulatory Clause	Balance Sheet Line Item	March 31, 2016		December 31, 2015
		(in millions)
Rate CNP Compliance	Under recovered regulatory clause revenues, current	$	22	$	43
Rate CNP PPA	Deferred under recovered regulatory clause revenues	105		99
Retail Energy Cost Recovery	Other regulatory liabilities, current	173		238
	Deferred over recovered regulatory clause revenues	64		—
Natural Disaster Reserve	Other regulatory liabilities, deferred	74		75

The balance of each regulatory clause recovery on the balance sheet follows:

Regulatory Clause	Balance Sheet Location	March 31, 2016		December 31, 2015
		(in millions)
Fuel Cost Recovery	Other regulatory liabilities, current	$	20	$	18
Purchased Power Capacity Recovery	Under recovered regulatory clause revenues	4		1
Environmental Cost Recovery	Under recovered regulatory clause revenues	17		19
Energy Conservation Cost Recovery	Other regulatory liabilities, current	2		4

Current And Actual Cost Estimate for Kemper IGCC

Mississippi Power's Kemper IGCC 2010 project estimate, current cost estimate (which includes the impacts of the Mississippi Supreme Court's (Court) decision discussed herein under "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order"), and actual costs incurred as of March 31, 2016, are as follows:

Cost Category	2010 Project Estimate(f)		Current Cost Estimate(a)			Actual Costs
	(in billions)
Plant Subject to Cost Cap(b)(g)	$	2.40	$	5.35		$	4.99
Lignite Mine and Equipment	0.21		0.23			0.23
CO2 Pipeline Facilities	0.14		0.11			0.12
AFUDC(c)	0.17		0.71			0.62
Combined Cycle and Related Assets Placed in Service – Incremental(d)(g)	—		0.02			0.01
General Exceptions	0.05		0.10			0.09
Deferred Costs(e)(g)	—		0.20			0.18
Additional DOE Grants(h)	—		(0.14		)	—
Total Kemper IGCC	$	2.97	$	6.58		$	6.24

(a) Amounts in the Current Cost Estimate reflect estimated costs through September 30, 2016.

(b) The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, net of the Initial DOE Grants and excluding the Cost Cap Exceptions. The Current Cost Estimate and the Actual Costs include non-incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service in August 2014 that are subject to the $2.88 billion cost cap and exclude post-in-service costs for the lignite mine. See "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" herein for additional information. The Current Cost Estimate and the Actual Costs reflect 100% of the costs of the Kemper IGCC. See note (g) for additional information.

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

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

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

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

(g) Beginning in the third quarter 2015, certain costs, including debt carrying costs (associated with assets placed in service and other non-CWIP accounts), that previously were deferred as regulatory assets are now being recognized through income; however, such costs continue to be included in the Current Cost Estimate and the Actual Costs at March 31, 2016.

(h) On April 8, 2016, Mississippi Power received approximately $137 million in additional grants from the DOE for the Kemper IGCC, which are expected to be used to reduce future rate impacts for customers.

XML

Fair Value Measurements (Tables)

3 Months Ended

Mar. 31, 2016

Fair Value Disclosures [Abstract]

Assets and liabilities measured at fair value on a recurring basis

As of March 31, 2016, assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows:

	Fair Value Measurements Using
As of March 31, 2016:	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Net Asset Value as a Practical Expedient (NAV)		Total
	(in millions)
Southern Company
Assets:
Energy-related derivatives	$	—	$	12	$	—	$	—	$	12
Interest rate derivatives	—		33		—		—		33
Nuclear decommissioning trusts(a)	624		898		—		16		1,538
Cash equivalents	503		—		—		—		503
Other investments	9		—		1		—		10
Total	$	1,136	$	943	$	1	$	16	$	2,096
Liabilities:
Energy-related derivatives	$	—	$	201	$	—	$	—	$	201
Interest rate derivatives	—		193		—		—		193
Total	$	—	$	394	$	—	$	—	$	394
Alabama Power
Assets:
Energy-related derivatives	$	—	$	3	$	—	$	—	$	3
Nuclear decommissioning trusts(b)
Domestic equity	365		67		—		—		432
Foreign equity	46		48		—		—		94
U.S. Treasury and government agency securities	—		25		—		—		25
Corporate bonds	11		137		—		—		148
Mortgage and asset backed securities	—		21		—		—		21
Private Equity	—		—		—		16		16
Other	—		9		—		—		9
Cash equivalents	321		—		—		—		321
Total	$	743	$	310	$	—	$	16	$	1,069
Liabilities:
Energy-related derivatives	$	—	$	49	$	—	$	—	$	49

	Fair Value Measurements Using
As of March 31, 2016:	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Net Asset Value as a Practical Expedient (NAV)		Total
	(in millions)
Georgia Power
Assets:
Energy-related derivatives	$	—	$	4	$	—	$	—	$	4
Interest rate derivatives	—		14		—		—		14
Nuclear decommissioning trusts(b) (c)
Domestic equity	180		1		—		—		181
Foreign equity	—		115		—		—		115
U.S. Treasury and government agency securities	—		111		—		—		111
Municipal bonds	—		66		—		—		66
Corporate bonds	—		146		—		—		146
Mortgage and asset backed securities	—		145		—		—		145
Other	22		7		—		—		29
Cash equivalents	57		—		—		—		57
Total	$	259	$	609	$	—	$	—	$	868
Liabilities:
Energy-related derivatives	$	—	$	11	$	—	$	—	$	11
Gulf Power
Assets:
Cash equivalents	$	20	$	—	$	—	$	—	$	20
Liabilities:
Energy-related derivatives	$	—	$	94	$	—	$	—	$	94
Interest rate derivatives	—		5		—		—		5
Total	$	—	$	99	$	—	$	—	$	99
Mississippi Power
Assets:
Cash equivalents	$	24	$	—	$	—	$	—	$	24
Liabilities:
Energy-related derivatives	$	—	$	44	$	—	$	—	$	44
Southern Power
Assets:
Energy-related derivatives	$	—	$	5	$	—	$	—	$	5
Interest rate derivatives	—		1		—		—		1
Cash equivalents	39		—		—		—		39
Total	$	39	$	6	$	—	$	—	$	45
Liabilities:
Energy-related derivatives	$	—	$	3	$	—	$	—	$	3

(a) For additional detail, see the nuclear decommissioning trusts sections for Alabama Power and Georgia Power in this table.

(b) Excludes receivables related to investment income, pending investment sales, payables related to pending investment purchases, and currencies.

(c) Includes the investment securities pledged to creditors and collateral received and excludes payables related to the securities lending program. As of March 31, 2016, approximately $58 million of the fair market value of Georgia Power's nuclear decommissioning trust funds' securities were on loan to creditors under the funds' managers' securities lending program.

Fair value measurements of investments calculated at net asset value per share as well as the nature and risk of those investments

As of March 31, 2016, the fair value measurements of private equity investments held in the nuclear decommissioning trust that are calculated at net asset value per share (or its equivalent) as a practical expedient, as well as the nature and risks of those investments, were as follows:

As of March 31, 2016:	Fair Value		Unfunded Commitments		Redemption Frequency	Redemption Notice Period
	(in millions)
Southern Company	$	16	$	29	Not Applicable	Not Applicable
Alabama Power	$	16	$	29	Not Applicable	Not Applicable

Financial instruments for which carrying amount did not equal fair value

As of March 31, 2016, 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, including securities due within one year:
Southern Company	$	28,341	$	29,827
Alabama Power	$	7,089	$	7,688
Georgia Power	$	10,549	$	11,400
Gulf Power	$	1,303	$	1,366
Mississippi Power	$	3,209	$	2,938
Southern Power	$	3,123	$	3,171

XML

Stockholders' Equity (Tables)

3 Months Ended

Mar. 31, 2016

Equity [Abstract]

Earnings per Share

Shares used to compute diluted earnings per share were as follows:

	Three Months Ended March 31, 2016	Three Months Ended March 31, 2015
	(in millions)
As reported shares	916	910
Effect of options and performance share award units	6	5
Diluted shares	922	915

Changes in Stockholders' Equity

The following table presents year-to-date changes in stockholders' equity of Southern Company:

	Number of Common Shares			Common Stockholders' Equity			Preferred and Preference Stock of Subsidiaries					Total Stockholders' Equity
	Issued	Treasury							Noncontrolling Interests(*)
	(in thousands)			(in millions)
Balance at December 31, 2015	915,073	(3,352	)	$	20,592		$	609	$	781		$	21,982
Consolidated net income attributable to Southern Company	—	—		485			—		—			485
Other comprehensive income (loss)	—	—		(114		)	—		—			(114		)
Stock issued	6,572	—		270			—		—			270
Stock-based compensation	—	—		60			—		—			60
Cash dividends on common stock	—	—		(497		)	—		—			(497		)
Contributions from noncontrolling interests	—	—		—			—		129			129
Distributions to noncontrolling interests	—	—		—			—		(4		)	(4		)
Purchase of membership interests from noncontrolling interests	—	—		—			—		(129		)	(129		)
Net income attributable to noncontrolling interests	—	—		—			—		1			1
Other	—	(35	)	1			—		—			1
Balance at March 31, 2016	921,645	(3,387	)	$	20,797		$	609	$	778		$	22,184
Balance at December 31, 2014	908,502	(725	)	$	19,949		$	756	$	221		$	20,926
Consolidated net income attributable to Southern Company	—	—		508			—		—			508
Other comprehensive income (loss)	—	—		(15		)	—		—			(15		)
Stock issued	3,094	—		112			—		—			112
Stock-based compensation	—	—		53			—		—			53
Stock repurchased, at cost	—	(2,599	)	(115		)	—		—			(115		)
Cash dividends on common stock	—	—		(478		)	—		—			(478		)
Other	—	(11	)	3			—		—			3
Balance at March 31, 2015	911,596	(3,335	)	$	20,017		$	756	$	221		$	20,994

(*) Primarily related to Southern Power Company.

XML

Financing (Tables)

3 Months Ended

Mar. 31, 2016

Debt Disclosure [Abstract]

Credit arrangements by company

The following table outlines the committed credit arrangements by company as of March 31, 2016:

	Expires											Executable Term Loans				Due Within One Year
Company	2016		2017		2018		2020	Total		Unused		One Year		Two Years		Term Out		No Term Out
								(in millions)				(in millions)				(in millions)
Southern Company (a)	$	—	$	—	$	1,000	$1,250	$	2,250	$	2,250	$	—	$	—	$	—	$	—
Alabama Power	40		—		500		800	1,340		1,340		—		—		—		40
Georgia Power	—		—		—		1,750	1,750		1,732		—		—		—		—
Gulf Power	75		40		165		—	280		280		45		—		45		40
Mississippi Power	205		—		—		—	205		180		30		15		45		160
Southern Power Company (b)	—		—		—		600	600		560		—		—		—		—
Other	70		—		—		—	70		70		20		—		20		50
Total	$	390	$	40	$	1,665	$4,400	$	6,495	$	6,412	$	95	$	15	$	110	$	290

(a) Excludes the $8.1 billion Bridge Agreement entered into in September 2015 that will be funded only to the extent necessary to provide financing for the Merger as discussed herein.

(b) Excluding its subsidiaries. See "Project Credit Facilities" below and Note (I) under "Southern Power" for additional information.

The table below summarizes each Project Credit Facility as of March 31, 2016.

Project	Maturity Date	Construction Loan Facility		Bridge Loan Facility		Total		Total Undrawn		Letter of Credit Facility		Total Undrawn
		(in millions)
Tranquillity	Earlier of COD or December 31, 2016	$	86	$	172	$	258	$	52	$	77	$	26
Roserock	Earlier of COD or November 30, 2016	63		180		243		121		23		16
Garland	Earlier of COD or November 30, 2016	86		308		394		309		49		32
Total		$	235	$	660	$	895	$	482	$	149	$	74

Schedule of Long-term Debt Financing Activities

The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first three months of 2016:

Company(a)	Senior Note Issuances		Senior Note Maturities and Redemptions		Revenue Bond Maturities Redemptions and Repurchases		Other Long-Term Debt Issuances			Other Long-Term Debt Redemptions and Maturities(b)
	(in millions)
Alabama Power	$	400	$	200	$	—	$	45		$	—
Georgia Power	650		250		4		—			1
Mississippi Power	—		—		—		1,100			426
Southern Power	—		—		—		2			3
Other	—		—		—		—			4
Elimination(c)	—		—		—		(200		)	—
Total	$	1,050	$	450	$	4	$	947		$	434

(a) Southern Company and Gulf Power did not issue or redeem any long-term debt during the first three months of 2016.    

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

(c) Intercompany loans from Southern Company to Mississippi Power eliminated in Southern Company's Consolidated Financial Statements.

XML

Retirement Benefits (Tables)

3 Months Ended

Mar. 31, 2016

Compensation and Retirement Disclosure [Abstract]

Pension Plans and Postretirement Plans

Components of the net periodic benefit costs for the three months ended March 31, 2016 were as follows:

Pension Plans	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power
	(in millions)
Three Months Ended March 31, 2016
Service cost	$	62		$	14		$	17		$	3		$	3
Interest cost	100			24			34			5			5
Expected return on plan assets	(187		)	(46		)	(64		)	(9		)	(9		)
Amortization:
Prior service costs	4			1			1			—			—
Net (gain)/loss	38			10			14			2			2
Net cost	$	17		$	3		$	2		$	1		$	1
Three Months Ended March 31, 2015
Service cost	$	64		$	15		$	18		$	3		$	3
Interest cost	111			26			38			5			5
Expected return on plan assets	(181		)	(45		)	(63		)	(8		)	(8		)
Amortization:
Prior service costs	6			2			3			—			—
Net (gain)/loss	54			14			19			3			3
Net cost	$	54		$	12		$	15		$	3		$	3

Postretirement Benefits	Southern Company			Alabama Power			Georgia Power			Gulf Power		Mississippi Power
	(in millions)
Three Months Ended March 31, 2016
Service cost	$	5		$	1		$	2		$	—	$	—
Interest cost	18			5			8			1		1
Expected return on plan assets	(14		)	(6		)	(6		)	—		—
Amortization:
Prior service costs	2			1			—			—		—
Net (gain)/loss	3			—			2			—		—
Net cost	$	14		$	1		$	6		$	1	$	1
Three Months Ended March 31, 2015
Service cost	$	6		$	1		$	2		$	—	$	—
Interest cost	19			5			8			1		1
Expected return on plan assets	(15		)	(6		)	(6		)	—		—
Amortization:
Prior service costs	1			1			—			—		—
Net (gain)/loss	5			—			3			—		—
Net cost	$	16		$	1		$	7		$	1	$	1

XML

Income Taxes (Tables)

3 Months Ended

Mar. 31, 2016

Income Tax Disclosure [Abstract]

Change in Unrecognized Tax Benefits

Changes during 2016 for unrecognized tax benefits were as follows:

	Mississippi Power		Southern Power		Southern Company
	(in millions)
Unrecognized tax benefits as of December 31, 2015	$	421	$	8	$	433
Tax positions from current periods	—		5		5
Balance as of March 31, 2016	$	421	$	13	$	438

Impact on Effective Tax Rate, If Recognized

The impact on the effective tax rate, if recognized, is as follows:

	As of March 31, 2016							As of December 31, 2015
	Mississippi Power			Southern Power		Southern Company		Southern Company
	(in millions)
Tax positions impacting the effective tax rate	$	(2	)	$	13	$	15	$	10
Tax positions not impacting the effective tax rate	423			—		423		423
Balance of unrecognized tax benefits	$	421		$	13	$	438	$	433

XML

Derivatives (Tables)

3 Months Ended

Mar. 31, 2016

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of derivatives

At March 31, 2016, 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	235	2020	2017
Alabama Power	60	2019	—
Georgia Power	65	2019	—
Gulf Power	74	2020	—
Mississippi Power	28	2018	—
Southern Power	8	2016	2017

Notional amount of interest rate derivatives

At March 31, 2016, the following interest rate derivatives were outstanding:

	Notional Amount			Interest Rate Received	Weighted Average Interest Rate Paid	Hedge Maturity Date		Fair Value Gain (Loss) at March 31, 2016
	(in millions)							(in millions)
Cash Flow Hedges of Forecasted Debt
Southern Company	$	1,500		3-month LIBOR	2.14%	November 2026		$	(55	)
Southern Company	1,200			3-month LIBOR	2.60%	November 2046		(127		)
Gulf Power	80			3-month LIBOR	2.32%	December 2026		(4		)
Cash Flow Hedges of Existing Debt
Georgia Power	200			3-month LIBOR + 0.40%	1.01%	August 2016		—
Fair Value Hedges on Existing Debt
Southern Company	250			1.30%	3-month LIBOR + 0.17%	August 2017		1
Southern Company	300			2.75%	3-month LIBOR + 0.92%	June 2020		10
Georgia Power	250			5.40%	3-month LIBOR + 4.02%	June 2018		3
Georgia Power	200			4.25%	3-month LIBOR + 2.46%	December 2019		6
Georgia Power	500			1.95%	3-month LIBOR + 0.76%	December 2018		5
Derivatives not Designated as Hedges
Southern Power	65		(a,d)	3-month LIBOR	2.50%	October 2016	(e)	—
Southern Power	47		(b,d)	3-month LIBOR	2.21%	October 2016	(e)	—
Southern Power	65		(c,d)	3-month LIBOR	2.21%	November 2016	(f)	—
Total	$	4,657						$	(161	)

(a) Swaption at RE Tranquillity LLC. See Note 12 to the financial statements of Southern Company and Note 2 to the financial statements of Southern Power in Item 8 of the Form 10-K for additional information.

(b) Swaption at RE Roserock LLC. See Note 12 to the financial statements of Southern Company and Note 2 to the financial statements of Southern Power in Item 8 of the Form 10-K for additional information.

(c) Swaption at RE Garland Holdings LLC. See Note 12 to the financial statements of Southern Company and Note 2 to the financial statements of Southern Power in Item 8 of the Form 10-K for additional information.

(d) Amortizing notional amount.

(e) Represents the mandatory settlement date. Settlement will be based on a 15-year amortizing swap.

(f) Represents the mandatory settlement date. Settlement will be based on a 12-year amortizing swap.

Fair value of energy-related derivatives and interest rate derivatives

At March 31, 2016, the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows:

Asset Derivatives at March 31, 2016
	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	$	2	$	1	$	1	$	—	$	—
Other deferred charges and assets	5		2		3		—		—
Total derivatives designated as hedging instruments for regulatory purposes	$	7	$	3	$	4	$	—	$	—	N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Other current assets(*)	$	4	$	—	$	—	$	—	$	—	$	4
Interest rate derivatives:
Other current assets	18		—		7		—		—		—
Other deferred charges and assets	14		—		7		—		—		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	36	$	—	$	14	$	—	$	—	$	4
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets(*)	$	1	$	—	$	—	$	—	$	—	$	1
Interest rate derivatives:
Other current assets(*)	1		—		—		—		—		1
Total derivatives not designated as hedging instruments	$	2	$	—	$	—	$	—	$	—	$	2
Total asset derivatives	$	45	$	3	$	18	$	—	$	—	$	6

(*) Southern Power includes current assets related to derivatives in "Assets from risk management activities."

Liability Derivatives at March 31, 2016
	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(*)	$	124	$	37	$	9	$	49	$	29
Other deferred credits and liabilities	74		12		2		45		15
Total derivatives designated as hedging instruments for regulatory purposes	$	198	$	49	$	11	$	94	$	44	N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Liabilities from risk management activities(*)	$	2	$	—	$	—	$	—	$	—	$	2
Interest rate derivatives:
Liabilities from risk management activities(*)	193		—		—		5		—		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	195	$	—	$	—	$	5	$	—	$	2
Derivatives not designated as hedging instruments
Energy-related derivatives:
Liabilities from risk management activities(*)	$	1	$	—	$	—	$	—	$	—	$	1
Total liability derivatives	$	394	$	49	$	11	$	99	$	44	$	3

(*) Georgia Power, Mississippi Power, and Southern Power include current liabilities related to derivatives in "Other current liabilities."

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

Asset Derivatives at December 31, 2015
	Fair Value
Derivative Category and Balance Sheet Location	Southern Company		Alabama Power		Georgia Power		Gulf Power		Mississippi Power		Southern Power
	(in millions)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets	$	3	$	1	$	2	$	—	$	—	N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Other current assets(*)	$	3	$	—	$	—	$	—	$	—	$	3
Interest rate derivatives:
Other current assets	19		—		5		1		—		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	22	$	—	$	5	$	1	$	—	$	3
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets(*)	$	1	$	—	$	—	$	—	$	—	$	1
Interest rate derivatives:
Other current assets(*)	3		—		—		—		—		3
Total derivatives not designated as hedging instruments	$	4	$	—	$	—	$	—	$	—	$	4
Total asset derivatives	$	29	$	1	$	7	$	1	$	—	$	7

(*) Southern Power includes current assets related to derivatives in "Assets from risk management activities."

Liability Derivatives at December 31, 2015
	Fair Value
Derivative Category and Balance Sheet Location	Southern Company		Alabama Power		Georgia Power		Gulf Power		Mississippi Power		Southern Power
	(in millions)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Liabilities from risk management activities(*)	$	130	$	40	$	12	$	49	$	29
Other deferred credits and liabilities	87		15		3		51		18
Total derivatives designated as hedging instruments for regulatory purposes	$	217	$	55	$	15	$	100	$	47	N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Liabilities from risk management activities(*)	$	2	$	—	$	—	$	—	$	—	$	2
Interest rate derivatives:
Liabilities from risk management activities	23		15		—		—		—		—
Other deferred credits and liabilities	7		—		6		—		—		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	32	$	15	$	6	$	—	$	—	$	2
Derivatives not designated as hedging instruments
Energy-related derivatives:
Liabilities from risk management activities(*)	$	1	$	—	$	—	$	—	$	—	$	1
Total liability derivatives	$	250	$	70	$	21	$	100	$	47	$	3

(*) Georgia Power, Mississippi Power, and Southern Power include current liabilities related to derivatives in "Other current liabilities."

Offsetting disclosure tables

Amounts related to energy-related derivative contracts and interest rate derivative contracts at March 31, 2016 and December 31, 2015 are presented in the following tables.

Derivative Contracts at March 31, 2016
	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		$	3		$	4		$	—	$	—	$	5
Gross amounts not offset in the Balance Sheet (b)	(10		)	(3		)	(3		)	—		—		(2		)
Net energy-related derivative assets	$	2		$	—		$	1		$	—	$	—	$	3
Interest rate derivatives:
Interest rate derivatives presented in the Balance Sheet (a)	$	33		$	—		$	14		$	—	$	—	$	1
Gross amounts not offset in the Balance Sheet (b)	(21		)	—			—			—		—		—
Net interest rate derivative assets	$	12		$	—		$	14		$	—	$	—	$	1
Liabilities
Energy-related derivatives:
Energy-related derivatives presented in the Balance Sheet (a)	$	201		$	49		$	11		$	94	$	44	$	3
Gross amounts not offset in the Balance Sheet (b)	(10		)	(3		)	(3		)	—		—		(2		)
Net energy-related derivative liabilities	$	191		$	46		$	8		$	94	$	44	$	1
Interest rate derivatives:
Interest rate derivatives presented in the Balance Sheet (a)	$	193		$	—		$	—		$	5	$	—	$	—
Gross amounts not offset in the Balance Sheet (b)	(21		)	—			—			—		—		—
Net interest rate derivative liabilities	$	172		$	—		$	—		$	5	$	—	$	—

(a) None of the registrants offsets fair value amounts for multiple derivative instruments executed with the same counterparty on the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented on the balance sheets are the same.

(b) Includes gross amounts subject to netting terms that are not offset on the balance sheets and any cash/financial collateral pledged or received.

Derivative Contracts at December 31, 2015
	Fair Value
	Southern Company			Alabama Power			Georgia Power			Gulf Power		Mississippi Power		Southern Power
	(in millions)
Assets
Energy-related derivatives:
Energy-related derivatives presented in the Balance Sheet (a)	$	7		$	1		$	2		$	—	$	—	$	4
Gross amounts not offset in the Balance Sheet (b)	(6		)	(1		)	(2		)	—		—		(1		)
Net energy-related derivative assets	$	1		$	—		$	—		$	—	$	—	$	3
Interest rate derivatives:
Interest rate derivatives presented in the Balance Sheet (a)	$	22		$	—		$	5		$	1	$	—	$	4
Gross amounts not offset in the Balance Sheet (b)	(9		)	—			(4		)	—		—		—
Net interest rate derivative assets	$	13		$	—		$	1		$	1	$	—	$	4
Liabilities
Energy-related derivatives:
Energy-related derivatives presented in the Balance Sheet (a)	$	220		$	55		$	15		$	100	$	47	$	3
Gross amounts not offset in the Balance Sheet (b)	(6		)	(1		)	(2		)	—		—		(1		)
Net energy-related derivative liabilities	$	214		$	54		$	13		$	100	$	47	$	2
Interest rate derivatives:
Interest rate derivatives presented in the Balance Sheet (a)	$	30		$	15		$	6		$	—	$	—	$	—
Gross amounts not offset in the Balance Sheet (b)	(9		)	—			(4		)	—		—		—
Net interest rate derivative liabilities	$	21		$	15		$	2		$	—	$	—	$	—

(a) None of the registrants offsets fair value amounts for multiple derivative instruments executed with the same counterparty on the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented on the balance sheets are the same.

(b) Includes gross amounts subject to netting terms that are not offset on the balance sheets and any cash/financial collateral pledged or received.

Pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments

At March 31, 2016 and December 31, 2015, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred were as follows:

Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet at March 31, 2016
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	$	(124	)	$	(37	)	$	(9	)	$	(49	)	$	(29	)
Other regulatory assets, deferred	(74		)	(12		)	(2		)	(45		)	(15		)
Other regulatory liabilities, current (a)	2			1			1			—			—
Other regulatory liabilities, deferred (b)	5			2			3			—			—
Total energy-related derivative gains (losses)	$	(191	)	$	(46	)	$	(7	)	$	(94	)	$	(44	)

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

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

Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet at December 31, 2015
Derivative Category and Balance Sheet Location	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power
	(in millions)
Energy-related derivatives:
Other regulatory assets, current	$	(130	)	$	(40	)	$	(12	)	$	(49	)	$	(29	)
Other regulatory assets, deferred	(87		)	(15		)	(3		)	(51		)	(18		)
Other regulatory liabilities, current(*)	3			1			2			—			—
Total energy-related derivative gains (losses)	$	(214	)	$	(54	)	$	(13	)	$	(100	)	$	(47	)

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

Pre-tax effects of interest rate derivatives, designated as cash flow hedging instruments

For the three months ended March 31, 2016 and 2015, the pre-tax effects of interest rate derivatives designated as cash flow hedging instruments were as follows:

Derivatives in Cash Flow Hedging Relationships	Gain (Loss) Recognized in OCI on Derivative (Effective Portion)						Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)
							Statements of Income Location	Amount
	2016			2015				2016			2015
	(in millions)							(in millions)
Southern Company
Interest rate derivatives	$	(190	)	$	(29	)	Interest expense, net of amounts capitalized	$	(3	)	$	(2	)
Alabama Power
Interest rate derivatives	$	(4	)	$	(6	)	Interest expense, net of amounts capitalized	$	(1	)	$	(1	)
Georgia Power
Interest rate derivatives	$	—		$	(23	)	Interest expense, net of amounts capitalized	$	(1	)	$	(1	)
Gulf Power
Interest rate derivatives	$	(5	)	$	—		Interest expense, net of amounts capitalized	$	—		$	—

Pre-tax effects of interest rate derivatives, designated as fair value hedging instruments

For the three months ended March 31, 2016 and 2015, the pre-tax effects of interest rate derivatives designated as fair value hedging instruments were as follows:

Derivatives in Fair Value Hedging Relationships
		Gain (Loss)
Derivative Category	Statements of Income Location	2016		2015
		(in millions)
Southern Company
Interest rate derivatives:	Interest expense, net of amounts capitalized	$	20	$	7
Georgia Power
Interest rate derivatives:	Interest expense, net of amounts capitalized	$	14	$	6

XML

Acquisitions (Tables)

3 Months Ended

Mar. 31, 2016

Business Combinations [Abstract]

Schedule of Business Acquisitions

During 2016, in accordance with its overall growth strategy, Southern Power acquired or contracted to acquire through its wholly-owned subsidiaries, Southern Renewable Partnerships, LLC or Southern Renewable Energy, Inc., the projects set forth in the following table. Acquisition-related costs were expensed as incurred and were not material. The acquisitions do not include any contingent consideration unless specifically noted.

Project Facility	Seller; Acquisition Date	Approx. Nameplate Capacity	Location	Southern Power Percentage Ownership		Expected/Actual COD	PPA Counterparties for Plant Output	PPA Contract Period	Approx. Purchase Price
		(MW)							(in millions)
SOLAR
Calipatria	Solar Frontier Americas Holding, LLC February 11, 2016	20	Imperial County, CA	90	%	February 11, 2016	San Diego Gas & Electric Company	20 years	$	51	(a)
East Pecos	First Solar, Inc. March 4, 2016	120	Pecos County, TX	100	%	Fourth quarter 2016	Austin Energy	15 years	$	41	(b)
WIND
Grant Wind	Apex Clean Energy Holdings, LLC April 7, 2016	151	Grant County, OK	100	%	April 8, 2016	Western Farmers, East Texas, and Northeast Texas Electric Cooperative	20 years	$	258	(c)
Passadumkeag	Quantam Wind Acquisition I, LLC	40	Penobscot County, ME	100	%	Second quarter 2016	Western Massachusetts Electric Company	15 years	$	127	(d)

(a) Calipatria - The total purchase price, including the minority owner, TRE's 10% ownership interest and contingent consideration of $6 million, is approximately $57 million. As of March 31, 2016, the fair values of the assets and liabilities acquired through the business combination were recorded as follows: $58 million as property, plant, and equipment, $1 million as a transmission interconnection prepaid, and $2 million as payables; however, the allocation of the purchase price to individual assets has not been finalized.

(b) East Pecos - The total purchase price is approximately $41 million. As of March 31, 2016, the fair values of the assets acquired through the business combination were recorded as $41 million to CWIP; however, the allocation of the purchase price to individual assets has not been finalized. Total construction costs, which include the acquisition price allocated to CWIP, are expected to be approximately $200 million to $220 million. The ultimate outcome of this matter cannot be determined at this time.

(c) Grant Wind - Subsequent to March 31, 2016, Southern Power acquired all of the outstanding membership interests of Grant Wind, LLC. The purchase price includes approximately $23 million of contingent consideration which may be adjusted based on performance testing and production over the first 10 years of operation.

(d) Passadumkeag - On March 11, 2016, Southern Power entered into an agreement to acquire all of the outstanding membership interests of Quantum Wind Acquisition I, LLC, which is expected to close in the second quarter 2016. The ultimate outcome of this matter cannot be determined at this time.

Schedule of Construction Projects

Through March 31, 2016, total costs of construction incurred for the projects below were $2.2 billion, of which $1.5 billion remains in CWIP. The ultimate outcome of these matters cannot be determined at this time.

Solar Facility	Seller	Approx. Nameplate Capacity	Location	Expected/Actual COD	PPA Counterparties for Plant Output	PPA Contract Period	Estimated Construction Costs
		(MW)					(in millions)
Butler	CERSM, LLC and Community Energy, Inc.	103	Taylor County, GA	Fourth quarter 2016	Georgia Power(a)	30 years	$	220	-	230	(b)
Desert Stateline	First Solar, Inc.	299(c)	San Bernardino County, CA	Through third quarter 2016	Southern California Edison Company (SCE)	20 years	$	1,200	-	1,300	(d)
Garland and Garland A	Recurrent Energy, LLC	205	Kern County, CA	Fourth quarter 2016   Third quarter 2016	SCE	15 years and 20 years	$	532	-	552	(e,f)
Roserock	Recurrent Energy, LLC	160	Pecos County, TX	Fourth quarter 2016	Austin Energy	20 years	$	333	-	353	(e,f)
Sandhills	N/A	146	Taylor County, GA	Fourth quarter 2016	Cobb, Flint, Irwin, Middle Georgia and Sawnee Electric Membership Corporations	25 years	$	260	-	280
Tranquillity	Recurrent Energy, LLC	205	Fresno County, CA	Third quarter 2016	Shell Energy North America (US), LP/SCE	18 years	$	473	-	493	(f,g)

(a) Butler - Affiliate PPA subject to FERC approval.

(b) Butler - Total estimated construction costs include the acquisition price of all outstanding membership interests of the related entity.

(c) Desert Stateline - The facility has a total of 299 MWs, of which 110 MWs were placed in service in the fourth quarter 2015 and 76 MWs were placed in service in the first quarter 2016. Subsequent to March 31, 2016, 38 MWs were placed in service. The remaining 75 MWs are expected to be placed in service by the end of the third quarter 2016.

(d) Desert Stateline - On March 29, 2016, Southern Power acquired an additional 15% interest in Desert Stateline. As a result, Southern Power and the class B member are entitled to 66% and 34%, respectively, of all cash distributions from Desert Stateline. In addition, Southern Power will continue to be entitled to substantially all of the federal tax benefits with respect to the transaction. Total estimated construction costs include the acquisition price allocated to CWIP; however, the allocation of the purchase price to individual assets has not been finalized.

(e) Total estimated construction costs include the acquisition price allocated to CWIP. During the first quarter 2016, the allocation of the purchase price to individual assets was finalized with no changes.

(f) Southern Power owns 100% of the class A membership interests and a wholly-owned subsidiary of the seller owns 100% of the class B membership interests. Southern Power and the class B member are entitled to 51% and 49%, respectively, of all cash distributions from the project.

XML

Segment and Related Information (Tables)

3 Months Ended

Mar. 31, 2016

Segment Reporting [Abstract]

Financial data for business segments

Financial data for business segments and products and services for the three months ended March 31, 2016 and 2015 was as follows:

	Electric Utilities
	Traditional Operating Companies		Southern Power		Eliminations			Total		All Other			Eliminations			Consolidated
	(in millions)
Three Months Ended March 31, 2016:
Operating revenues	$	3,742	$	315	$	(103	)	$	3,954	$	47		$	(36	)	$	3,965
Segment net income (loss)(a)(b)	464		50		—			514		(26		)	(3		)	485
Total assets at March 31, 2016	$	69,240	$	8,999	$	(396	)	$	77,843	$	2,070		$	(1,178	)	$	78,735
Three Months Ended March 31, 2015:
Operating revenues	$	3,948	$	348	$	(124	)	$	4,172	$	40		$	(29	)	$	4,183
Segment net income (loss)(a)(b)	477		33		—			510		3			(5		)	508
Total assets at December 31, 2015	$	69,052	$	8,905	$	(397	)	$	77,560	$	1,819		$	(1,061	)	$	78,318

(a) Attributable to Southern Company.

(b) Segment net income (loss) for the traditional operating companies includes pre-tax charges for estimated probable losses on the Kemper IGCC of $53 million ($33 million after tax) and $9 million ($6 million after tax) for the three months ended March 31, 2016 and 2015, respectively. See Note (B) under "Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" for additional information.

Financial data for products and services

Products and Services

	Electric Utilities' Revenues
Period	Retail		Wholesale		Other		Total
	(in millions)
Three Months Ended March 31, 2016	$	3,377	$	396	$	181	$	3,954
Three Months Ended March 31, 2015	3,542		467		163		4,172

XML

Contingencies and Regulatory Matters - Recovery Balance of Each Regulatory Clause - Alabama Power (Details) - Alabama Power [Member] - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Under recovered regulatory clause revenues, current [Member]
Loss Contingencies [Line Items]
Rate CNP Compliance	$ 22	$ 43
Deferred under recovered regulatory clause revenues [Member]
Loss Contingencies [Line Items]
Rate CNP PPA	105	99
Other regulatory liabilities, current [Member]
Loss Contingencies [Line Items]
Retail Energy Cost Recovery	173	238
Deferred Over Recovered Regulatory Clause Revenues [Member]
Loss Contingencies [Line Items]
Retail Energy Cost Recovery	64	0
Other regulatory liabilities, deferred [Member]
Loss Contingencies [Line Items]
Natural Disaster Reserve	$ 74	$ 75

XML

Contingencies and Regulatory Matters - Recovery Balance of Each Regulatory Clause - Gulf Power (Details) - Gulf Power [Member] - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Under recovered regulatory clause revenues [Member]
Loss Contingencies [Line Items]
Purchased Power Capacity Recovery	$ 4	$ 1
Other regulatory liabilities, current [Member]
Loss Contingencies [Line Items]
Fuel Cost Recovery	20	18
Environmental Cost Recovery	17	19
Energy Conservation Cost Recovery	$ 2	$ 4

XML

Contingencies and Regulatory Matters - Current And Actual Cost Estimate (Details) - Mississippi Power [Member] - USD ($) $ in Millions		3 Months Ended	12 Months Ended
	Apr. 08, 2016	Mar. 31, 2016	Dec. 31, 2012	Oct. 06, 2014
Loss Contingencies [Line Items]
Cost Related to Grant Funding			$ 245
Kemper IGCC [Member]
Loss Contingencies [Line Items]
Plant Subject to Cost Cap		$ 4,990	$ 2,880
Lignite Mine and Equipment		230
CO2 Pipeline Facilities		120
AFUDC		620
Combined Cycle and Related Assets Placed in Service – Incremental		10
General Exceptions		90
Deferred Costs		180
Total Kemper IGCC, Actual Costs		6,240
Cost Related to Grant Funding		$ 0
Purchase of Interest		100.00%		15.00%
Project Estimate [Member] | Kemper IGCC [Member]
Loss Contingencies [Line Items]
Plant Subject to Cost Cap		$ 2,400
Lignite Mine and Equipment		210
CO2 Pipeline Facilities		140
AFUDC		170
Combined Cycle and Related Assets Placed in Service – Incremental		0
General Exceptions		50
Deferred Costs		0
Total Kemper IGCC, Actual Costs		2,970
Cost Related to Grant Funding		0
Current Estimate [Member] | Kemper IGCC [Member]
Loss Contingencies [Line Items]
Plant Subject to Cost Cap		5,350
Lignite Mine and Equipment		230
CO2 Pipeline Facilities		110
AFUDC		710
Combined Cycle and Related Assets Placed in Service – Incremental		20
General Exceptions		100
Deferred Costs		200
Total Kemper IGCC, Actual Costs		6,580
Cost Related to Grant Funding		$ (140)
Subsequent Event [Member] | Kemper IGCC [Member]
Loss Contingencies [Line Items]
Government Grants Received	$ 137

XML

Contingencies and Regulatory Matters - Narrative (Details)									1 Months Ended			3 Months Ended		6 Months Ended	12 Months Ended								51 Months Ended	84 Months Ended
	May. 01, 2016 USD ($)	Apr. 08, 2016 USD ($)	Dec. 03, 2015 USD ($)	Jul. 07, 2015 USD ($)	Jun. 30, 2015 USD ($)	Apr. 15, 2015 USD ($)	Jan. 01, 2014 USD ($)	Mar. 19, 2013	Dec. 31, 2015 USD ($)	Feb. 28, 2013 USD ($)	Jan. 31, 2013 USD ($)	Mar. 31, 2016 USD ($) clause mi MW	Mar. 31, 2015 USD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)	Dec. 31, 2012 USD ($)	Dec. 31, 2010	Dec. 31, 2009 USD ($)	Dec. 31, 2008 USD ($)	Mar. 31, 2016 USD ($) mi	Dec. 31, 2022	Apr. 14, 2016 USD ($)	Apr. 01, 2016 USD ($)	Feb. 01, 2016 USD ($)	Jan. 13, 2016 USD ($)	Jan. 05, 2016 USD ($)	Jul. 10, 2015 USD ($)	Oct. 06, 2014
Loss Contingencies [Line Items]
Maximum Borrowing Capacity												$ 6,495,000,000											$ 6,495,000,000
Construction in Progress, Gross									$ 9,082,000,000			9,406,000,000		$ 9,082,000,000		$ 9,082,000,000							9,406,000,000
Other Regulatory Assets Deferred									4,989,000,000			4,957,000,000		4,989,000,000		4,989,000,000							4,957,000,000
Projected Balance Of Regulatory Assets									402,000,000			394,000,000		402,000,000		402,000,000							394,000,000
Kemper IGCC [Member]
Loss Contingencies [Line Items]
Pre-Tax Charge To Income												53,000,000	$ 9,000,000
After Tax Charge To Income												33,000,000	$ 6,000,000
Georgia Power [Member]
Loss Contingencies [Line Items]
Environmental Exit Costs, Assets Previously Disposed, Liability for Remediation												28,000,000											28,000,000
Additional Construction Capital Costs					$ 3,100,000,000							5,440,000,000		160,000,000
Percentage of Proportionate Share Owed in Consortium Agreement																						45.70%
Maximum Borrowing Capacity												$ 1,750,000,000											1,750,000,000
Increase (Decrease) In Projected Certified Construction Capital Costs												5.00%
Estimated In-service Capital Cost																					$ 4,400,000,000
Amendment To Estimated In-service Capital Cost										$ 4,800,000,000
Delay Of Estimated In-service Date						18 months
Construction in Progress, Gross									4,775,000,000			$ 4,817,000,000		4,775,000,000		4,775,000,000							4,817,000,000
Other Regulatory Assets Deferred									2,152,000,000			2,138,000,000		2,152,000,000		2,152,000,000							2,138,000,000
Projected Balance Of Regulatory Assets									123,000,000			126,000,000		123,000,000		123,000,000							126,000,000
Georgia Power [Member] | Maximum [Member]
Loss Contingencies [Line Items]
Additional Construction Capital Costs																						$ 114,000,000
Georgia Power [Member] | Other Current Liabilities [Member]
Loss Contingencies [Line Items]
Over Recovered Fuel Balance												177,000,000											177,000,000
Georgia Power [Member] | Other deferred credits and liabilities [Member]
Loss Contingencies [Line Items]
Over Recovered Fuel Balance									116,000,000					116,000,000		116,000,000
Georgia Power [Member] | Plant Vogtle Units 3 And 4 [Member]
Loss Contingencies [Line Items]
Maximum Borrowing Capacity																												$ 920,000,000
Estimated In-service Capital Cost						$ 5,000,000,000
Monthly Operational Readiness Costs						$ 10,000,000
Monthly Financing Costs												27,000,000
Construction Financing Costs												2,400,000,000
Construction in Progress, Gross												3,700,000,000											3,700,000,000
Georgia Power [Member] | Plant Vogtle Units 3 And 4 [Member] | Pending Litigation [Member]
Loss Contingencies [Line Items]
Project Settlement Cost To Be Capitalized									350,000,000					350,000,000		350,000,000
Project Settlement Cost To Be Capitalized, Amount Paid To Date									241,000,000					241,000,000		241,000,000
Gulf Power [Member]
Loss Contingencies [Line Items]
Environmental Exit Costs, Assets Previously Disposed, Liability for Remediation												46,000,000											46,000,000
Maximum Borrowing Capacity												280,000,000											280,000,000
Construction in Progress, Gross									48,000,000			57,000,000		48,000,000		48,000,000							57,000,000
Reduction In Depreciation Expense																		$ 62,500,000
Reduction In Depreciation Expense Year One												$ 5,600,000				20,100,000	$ 8,400,000
Number Of Regulatory Clauses | clause												4
Other Regulatory Assets Deferred									427,000,000			$ 420,000,000		427,000,000		427,000,000							420,000,000
Projected Balance Of Regulatory Assets									90,000,000			90,000,000		90,000,000		90,000,000							90,000,000
Mississippi Power [Member]
Loss Contingencies [Line Items]
Ownership Percentage in Project One																			50.00%
Over Recovered Fuel Cost									71,000,000			80,000,000		71,000,000		71,000,000							80,000,000
Approved Increase (Decrease) in Annual Billing Based on Fuel Cost Recovery Rate																											$ (36,000,000)		$ (120,000,000)
Maximum Borrowing Capacity												205,000,000											205,000,000
Construction in Progress, Gross									2,254,000,000			$ 2,400,000,000		2,254,000,000		2,254,000,000							$ 2,400,000,000
Annual PEP Filing Rate Increase Amount																										$ 5,000,000
Plant Capacity Under Coal Gasification Combined Cycle Technology (in MWs) | MW												582
Co Two Pipeline Infrastructure (in miles) | mi												61											61
Costs associated with CCP12 grant funds																			$ 245,000,000
Other Property And Investments												$ 6,000,000											$ 6,000,000
Lignite Mining Costs												75,000,000											75,000,000
Materials, Supplies, and Other												45,000,000											45,000,000
Cost deferred in other regulatory assets												22,000,000											22,000,000
Other Regulatory Assets Deferred									525,000,000			520,000,000		525,000,000		525,000,000							520,000,000
Other deferred charges and assets												11,000,000											11,000,000
Increase Retail Rates In Year One								15.00%
Increase Retail Rates In Year Two							3.00%
Settlement Agreement Collection Amount To Mitigate Rate Impact Year Two							$ 156,000,000
Retail Rate Recovery				$ 342,000,000
Carrying Costs Associated With Retail Rate Recovery				$ 29,000,000
Projected Balance Of Regulatory Assets									95,000,000			101,000,000		95,000,000		95,000,000							101,000,000
Regulatory Liabilities												$ 3,000,000											$ 3,000,000
Percentage of Carbon Dioxide Captured from Project												70.00%											70.00%
Percentage of Contract to Purchase Carbon Dioxide from Project												30.00%											30.00%
Mississippi Power [Member] | Minimum [Member]
Loss Contingencies [Line Items]
Costs Due To Extension Of In-service Date												$ 25,000,000
Mississippi Power [Member] | Maximum [Member]
Loss Contingencies [Line Items]
Costs Due To Extension Of In-service Date												35,000,000
Mississippi Power [Member] | Construction in Progress [Member]
Loss Contingencies [Line Items]
Loss Contingency, Estimate of Possible Loss												2,470,000,000											$ 2,470,000,000
Mississippi Power [Member] | MRA Revenue [Member]
Loss Contingencies [Line Items]
Over Recovered Fuel Cost									24,000,000			25,000,000		$ 24,000,000		$ 24,000,000							25,000,000
Mississippi Power [Member] | Electricity Generation Plant, Non-Nuclear [Member]
Loss Contingencies [Line Items]
Estimated Cost											$ 2,400,000,000								2,400,000,000
Alternate Financing										$ 1,000,000,000
Mississippi Power [Member] | Kemper IGCC [Member]
Loss Contingencies [Line Items]
Estimated Cost												4,990,000,000							$ 2,880,000,000
Costs associated with CCP12 grant funds												0
Other Regulatory Assets Deferred												196,000,000											196,000,000
Pre-Tax Charge To Income												53,000,000											2,470,000,000
After Tax Charge To Income												33,000,000											$ 1,520,000,000
Monthly Charge Of Allowance For Equity Funds Used During Construction												14,000,000
Monthly Cost Regulatory Assets Deferred												$ 2,000,000
Purchase of Interest												100.00%											100.00%								15.00%
Maximum Cap Construction Cost												$ 6,240,000,000
Regulatory Assets												120,000,000											$ 120,000,000
Projected Balance Of Regulatory Assets												98,000,000											98,000,000
Mississippi Power [Member] | Kemper IGCC [Member] | Current Estimate [Member]
Loss Contingencies [Line Items]
Estimated Cost												5,350,000,000
Costs associated with CCP12 grant funds												(140,000,000)
Maximum Cap Construction Cost												$ 6,580,000,000
Mississippi Power [Member] | Kemper IGCC [Member] | In-Service Asset Proposal [Member]
Loss Contingencies [Line Items]
PSC Retail Rate Increase (Decrease)			$ 126,000,000																											$ 159,000,000
Public Utilities, Approved Equity Capital Structure, Percentage			49.733%
Public Utilities, Approved Return on Equity, Percentage			9.225%
Customer Refund									$ 11,000,000
Period to File Subsequent Rate Request			18 months
Mississippi Power [Member] | Kemper IGCC [Member] | Minimum [Member]
Loss Contingencies [Line Items]
Amortization Period of Regulatory Assets and Liabilities												2 years
Mississippi Power [Member] | Kemper IGCC [Member] | Maximum [Member]
Loss Contingencies [Line Items]
Amortization Period of Regulatory Assets and Liabilities												10 years
Mississippi Power [Member] | Kemper IGCC [Member] | Property, Plant and Equipment [Member]
Loss Contingencies [Line Items]
Estimated Cost												$ 3,610,000,000
Mississippi Power [Member] | Kemper IGCC [Member] | Other current assets [Member]
Loss Contingencies [Line Items]
Estimated Cost												1,000,000
Mississippi Power [Member] | Kemper IGCC [Member] | Current Assets [Member]
Loss Contingencies [Line Items]
Regulatory Assets												$ 22,000,000											$ 22,000,000
Mississippi Power [Member] | Mine [Member]
Loss Contingencies [Line Items]
Term of Management Fee Contract																				40 years
Subsequent Event [Member] | Georgia Power [Member]
Loss Contingencies [Line Items]
Rate ECR Increase Decrease																									15.00%
Approved Increase (Decrease) in Annual Billing Based on Fuel Cost Recovery Rate																									$ (313,000,000)
Subsequent Event [Member] | Mississippi Power [Member]
Loss Contingencies [Line Items]
Increase in Base Rate Under Cost Based Electric Tariff Due to Settlement	$ 7,000,000
Increase (Decrease) in Revenue to be Received from Base Rate Change															$ 5,000,000
AFUDC Cost															$ 6,000,000
Subsequent Event [Member] | Mississippi Power [Member] | Kemper IGCC [Member]
Loss Contingencies [Line Items]
Government Grants Received		$ 137,000,000
Scenario, Forecast [Member] | Georgia Power And Atlanta Gas Light Company [Member]
Loss Contingencies [Line Items]
Percentage Basis, Net Merger Savings																								40.00%
Customers [Member] | Scenario, Forecast [Member]
Loss Contingencies [Line Items]
Percentage Basis, Net Merger Savings																								60.00%

XML

Fair Value Measurements - Assets and Liabilities Measured at Fair Value on a Recurring Basis (Details) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Fair Value, Measurements, Recurring [Member]
Assets:
Energy-related derivatives	$ 12
Interest rate derivatives	33
Nuclear decommissioning trusts	1,538
Cash equivalents	503
Other investments	10
Total	2,096
Liabilities:
Energy-related derivatives	201
Interest rate derivatives	193
Total	394
Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member]
Assets:
Energy-related derivatives	0
Interest rate derivatives	0
Nuclear decommissioning trusts	624
Cash equivalents	503
Other investments	9
Total	1,136
Liabilities:
Energy-related derivatives	0
Interest rate derivatives	0
Total	0
Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member]
Assets:
Energy-related derivatives	12
Interest rate derivatives	33
Nuclear decommissioning trusts	898
Cash equivalents	0
Other investments	0
Total	943
Liabilities:
Energy-related derivatives	201
Interest rate derivatives	193
Total	394
Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member]
Assets:
Energy-related derivatives	0
Interest rate derivatives	0
Nuclear decommissioning trusts	0
Cash equivalents	0
Other investments	1
Total	1
Liabilities:
Energy-related derivatives	0
Interest rate derivatives	0
Total	0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Net Asset Value As A Practical Expedient [Member]
Assets:
Energy-related derivatives	0
Interest rate derivatives	0
Nuclear decommissioning trusts	16
Cash equivalents	0
Other investments	0
Total	16
Liabilities:
Energy-related derivatives	0
Interest rate derivatives	0
Total	0
Alabama Power [Member]
Assets:
Energy-related derivatives	3	$ 1
Liabilities:
Energy-related derivatives	49	70
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member]
Assets:
Energy-related derivatives	3
Cash equivalents	321
Total	1,069
Liabilities:
Energy-related derivatives	49
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Domestic Equity [Member]
Assets:
Nuclear decommissioning trusts	432
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Foreign equity [Member]
Assets:
Nuclear decommissioning trusts	94
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | U.S. Treasury and government agency securities [Member]
Assets:
Nuclear decommissioning trusts	25
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Corporate bonds [Member]
Assets:
Nuclear decommissioning trusts	148
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Mortgage and asset backed securities [Member]
Assets:
Nuclear decommissioning trusts	21
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Private Equity Funds [Member]
Assets:
Nuclear decommissioning trusts	16
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Other investments [Member]
Assets:
Nuclear decommissioning trusts	9
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member]
Assets:
Energy-related derivatives	0
Cash equivalents	321
Total	743
Liabilities:
Energy-related derivatives	0
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Domestic Equity [Member]
Assets:
Nuclear decommissioning trusts	365
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Foreign equity [Member]
Assets:
Nuclear decommissioning trusts	46
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | U.S. Treasury and government agency securities [Member]
Assets:
Nuclear decommissioning trusts	0
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Corporate bonds [Member]
Assets:
Nuclear decommissioning trusts	11
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Mortgage and asset backed securities [Member]
Assets:
Nuclear decommissioning trusts	0
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Private Equity Funds [Member]
Assets:
Nuclear decommissioning trusts	0
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other investments [Member]
Assets:
Nuclear decommissioning trusts	0
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member]
Assets:
Energy-related derivatives	3
Cash equivalents	0
Total	310
Liabilities:
Energy-related derivatives	49
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Domestic Equity [Member]
Assets:
Nuclear decommissioning trusts	67
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Foreign equity [Member]
Assets:
Nuclear decommissioning trusts	48
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | U.S. Treasury and government agency securities [Member]
Assets:
Nuclear decommissioning trusts	25
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Corporate bonds [Member]
Assets:
Nuclear decommissioning trusts	137
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Mortgage and asset backed securities [Member]
Assets:
Nuclear decommissioning trusts	21
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Private Equity Funds [Member]
Assets:
Nuclear decommissioning trusts	0
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other investments [Member]
Assets:
Nuclear decommissioning trusts	9
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member]
Assets:
Energy-related derivatives	0
Cash equivalents	0
Total	0
Liabilities:
Energy-related derivatives	0
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Domestic Equity [Member]
Assets:
Nuclear decommissioning trusts	0
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Foreign equity [Member]
Assets:
Nuclear decommissioning trusts	0
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | U.S. Treasury and government agency securities [Member]
Assets:
Nuclear decommissioning trusts	0
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Corporate bonds [Member]
Assets:
Nuclear decommissioning trusts	0
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Mortgage and asset backed securities [Member]
Assets:
Nuclear decommissioning trusts	0
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Private Equity Funds [Member]
Assets:
Nuclear decommissioning trusts	0
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other investments [Member]
Assets:
Nuclear decommissioning trusts	0
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Net Asset Value As A Practical Expedient [Member]
Assets:
Energy-related derivatives	0
Cash equivalents	0
Total	16
Liabilities:
Energy-related derivatives	0
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Net Asset Value As A Practical Expedient [Member] | Domestic Equity [Member]
Assets:
Nuclear decommissioning trusts	0
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Net Asset Value As A Practical Expedient [Member] | Foreign equity [Member]
Assets:
Nuclear decommissioning trusts	0
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Net Asset Value As A Practical Expedient [Member] | U.S. Treasury and government agency securities [Member]
Assets:
Nuclear decommissioning trusts	0
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Net Asset Value As A Practical Expedient [Member] | Corporate bonds [Member]
Assets:
Nuclear decommissioning trusts	0
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Net Asset Value As A Practical Expedient [Member] | Mortgage and asset backed securities [Member]
Assets:
Nuclear decommissioning trusts	0
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Net Asset Value As A Practical Expedient [Member] | Private Equity Funds [Member]
Assets:
Nuclear decommissioning trusts	16
Alabama Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Net Asset Value As A Practical Expedient [Member] | Other investments [Member]
Assets:
Nuclear decommissioning trusts	0
Georgia Power [Member]
Assets:
Energy-related derivatives	18	7
Nuclear decommissioning trusts	58
Liabilities:
Energy-related derivatives	11	21
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member]
Assets:
Energy-related derivatives	4
Interest rate derivatives	14
Cash equivalents	57
Total	868
Liabilities:
Energy-related derivatives	11
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Domestic Equity [Member]
Assets:
Nuclear decommissioning trusts	181
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Foreign equity [Member]
Assets:
Nuclear decommissioning trusts	115
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | U.S. Treasury and government agency securities [Member]
Assets:
Nuclear decommissioning trusts	111
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Municipal bonds [Member]
Assets:
Nuclear decommissioning trusts	66
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Corporate bonds [Member]
Assets:
Nuclear decommissioning trusts	146
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Mortgage and asset backed securities [Member]
Assets:
Nuclear decommissioning trusts	145
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Other investments [Member]
Assets:
Nuclear decommissioning trusts	29
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member]
Assets:
Energy-related derivatives	0
Interest rate derivatives	0
Cash equivalents	57
Total	259
Liabilities:
Energy-related derivatives	0
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Domestic Equity [Member]
Assets:
Nuclear decommissioning trusts	180
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Foreign equity [Member]
Assets:
Nuclear decommissioning trusts	0
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | U.S. Treasury and government agency securities [Member]
Assets:
Nuclear decommissioning trusts	0
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Municipal bonds [Member]
Assets:
Nuclear decommissioning trusts	0
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Corporate bonds [Member]
Assets:
Nuclear decommissioning trusts	0
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Mortgage and asset backed securities [Member]
Assets:
Nuclear decommissioning trusts	0
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Other investments [Member]
Assets:
Nuclear decommissioning trusts	22
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member]
Assets:
Energy-related derivatives	4
Interest rate derivatives	14
Cash equivalents	0
Total	609
Liabilities:
Energy-related derivatives	11
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Domestic Equity [Member]
Assets:
Nuclear decommissioning trusts	1
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Foreign equity [Member]
Assets:
Nuclear decommissioning trusts	115
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | U.S. Treasury and government agency securities [Member]
Assets:
Nuclear decommissioning trusts	111
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Municipal bonds [Member]
Assets:
Nuclear decommissioning trusts	66
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Corporate bonds [Member]
Assets:
Nuclear decommissioning trusts	146
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Mortgage and asset backed securities [Member]
Assets:
Nuclear decommissioning trusts	145
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Other investments [Member]
Assets:
Nuclear decommissioning trusts	7
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member]
Assets:
Energy-related derivatives	0
Interest rate derivatives	0
Cash equivalents	0
Total	0
Liabilities:
Energy-related derivatives	0
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Domestic Equity [Member]
Assets:
Nuclear decommissioning trusts	0
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Foreign equity [Member]
Assets:
Nuclear decommissioning trusts	0
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | U.S. Treasury and government agency securities [Member]
Assets:
Nuclear decommissioning trusts	0
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Municipal bonds [Member]
Assets:
Nuclear decommissioning trusts	0
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Corporate bonds [Member]
Assets:
Nuclear decommissioning trusts	0
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Mortgage and asset backed securities [Member]
Assets:
Nuclear decommissioning trusts	0
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Other investments [Member]
Assets:
Nuclear decommissioning trusts	0
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Net Asset Value As A Practical Expedient [Member]
Assets:
Energy-related derivatives	0
Interest rate derivatives	0
Cash equivalents	0
Total	0
Liabilities:
Energy-related derivatives	0
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Net Asset Value As A Practical Expedient [Member] | Domestic Equity [Member]
Assets:
Nuclear decommissioning trusts	0
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Net Asset Value As A Practical Expedient [Member] | Foreign equity [Member]
Assets:
Nuclear decommissioning trusts	0
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Net Asset Value As A Practical Expedient [Member] | U.S. Treasury and government agency securities [Member]
Assets:
Nuclear decommissioning trusts	0
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Net Asset Value As A Practical Expedient [Member] | Municipal bonds [Member]
Assets:
Nuclear decommissioning trusts	0
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Net Asset Value As A Practical Expedient [Member] | Corporate bonds [Member]
Assets:
Nuclear decommissioning trusts	0
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Net Asset Value As A Practical Expedient [Member] | Mortgage and asset backed securities [Member]
Assets:
Nuclear decommissioning trusts	0
Georgia Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Net Asset Value As A Practical Expedient [Member] | Other investments [Member]
Assets:
Nuclear decommissioning trusts	0
Gulf Power [Member]
Assets:
Energy-related derivatives	0	1
Liabilities:
Energy-related derivatives	99	100
Gulf Power [Member] | Fair Value, Measurements, Recurring [Member]
Assets:
Cash equivalents	20
Liabilities:
Energy-related derivatives	94
Interest rate derivatives	5
Total	99
Gulf Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member]
Assets:
Cash equivalents	20
Liabilities:
Energy-related derivatives	0
Interest rate derivatives	0
Total	0
Gulf Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member]
Assets:
Cash equivalents	0
Liabilities:
Energy-related derivatives	94
Interest rate derivatives	5
Total	99
Gulf Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member]
Assets:
Cash equivalents	0
Liabilities:
Energy-related derivatives	0
Interest rate derivatives	0
Total	0
Gulf Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Net Asset Value As A Practical Expedient [Member]
Assets:
Cash equivalents	0
Liabilities:
Energy-related derivatives	0
Interest rate derivatives	0
Total	0
Mississippi Power [Member]
Assets:
Energy-related derivatives	0	0
Liabilities:
Energy-related derivatives	44	47
Mississippi Power [Member] | Fair Value, Measurements, Recurring [Member]
Assets:
Cash equivalents	24
Liabilities:
Energy-related derivatives	44
Mississippi Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member]
Assets:
Cash equivalents	24
Liabilities:
Energy-related derivatives	0
Mississippi Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member]
Assets:
Cash equivalents	0
Liabilities:
Energy-related derivatives	44
Mississippi Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member]
Assets:
Cash equivalents	0
Liabilities:
Energy-related derivatives	0
Mississippi Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Net Asset Value As A Practical Expedient [Member]
Assets:
Cash equivalents	0
Liabilities:
Energy-related derivatives	0
Southern Power [Member]
Assets:
Energy-related derivatives	6	7
Liabilities:
Energy-related derivatives	3	$ 3
Southern Power [Member] | Fair Value, Measurements, Recurring [Member]
Assets:
Energy-related derivatives	5
Interest rate derivatives	1
Cash equivalents	39
Total	45
Liabilities:
Energy-related derivatives	3
Southern Power [Member] | Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets for Identical Assets (Level 1) [Member]
Assets:
Energy-related derivatives	0
Interest rate derivatives	0
Cash equivalents	39
Total	39
Liabilities:
Energy-related derivatives	0
Southern Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member]
Assets:
Energy-related derivatives	5
Interest rate derivatives	1
Cash equivalents	0
Total	6
Liabilities:
Energy-related derivatives	3
Southern Power [Member] | Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member]
Assets:
Energy-related derivatives	0
Interest rate derivatives	0
Cash equivalents	0
Total	0
Liabilities:
Energy-related derivatives	0
Southern Power [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Net Asset Value As A Practical Expedient [Member]
Assets:
Energy-related derivatives	0
Interest rate derivatives	0
Cash equivalents	0
Total	0
Liabilities:
Energy-related derivatives	$ 0

XML

Fair Value Measurements - Fair Value Measurements Of Investments Calculated At Net Asset Value Per Share (Details) - Private Equity Funds [Member] $ in Millions	Mar. 31, 2016 USD ($)
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Fair Value	$ 16
Unfunded Commitments	29
Alabama Power [Member]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Fair Value	16
Unfunded Commitments	$ 29

XML

Fair Value Measurements - Financial Instruments for which Carrying Amount did not Equal Fair Value (Details) $ in Millions	Mar. 31, 2016 USD ($)
Southern Company [Member]
Long-term debt:
Long-term debt, including securities due within one year, Carrying Amount	$ 28,341
Long-term debt, including securities due within one year, Fair Value	29,827
Alabama Power [Member]
Long-term debt:
Long-term debt, including securities due within one year, Carrying Amount	7,089
Long-term debt, including securities due within one year, Fair Value	7,688
Georgia Power [Member]
Long-term debt:
Long-term debt, including securities due within one year, Carrying Amount	10,549
Long-term debt, including securities due within one year, Fair Value	11,400
Gulf Power [Member]
Long-term debt:
Long-term debt, including securities due within one year, Carrying Amount	1,303
Long-term debt, including securities due within one year, Fair Value	1,366
Mississippi Power [Member]
Long-term debt:
Long-term debt, including securities due within one year, Carrying Amount	3,209
Long-term debt, including securities due within one year, Fair Value	2,938
Southern Power [Member]
Long-term debt:
Long-term debt, including securities due within one year, Carrying Amount	3,123
Long-term debt, including securities due within one year, Fair Value	$ 3,171

XML

Fair Value Measurements - Narrative (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Fair Value, Option, Quantitative Disclosures [Line Items]
Increase (decrease) in fair value of funds	$ (20)	$ (33)
Private Equity Funds [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Liquidating Investment, Remaining Period	10 years
Alabama Power [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Increase (decrease) in fair value of funds	$ (11)	(15)
Georgia Power [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Increase (decrease) in fair value of funds	$ (9)	$ (18)

XML

Stockholders' Equity - Earnings per Share (Details) - shares shares in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Earnings per Share
As reported shares	916	910
Diluted shares	922	915
Southern Company [Member]
Earnings per Share
As reported shares	916	910
Effect of options and performance share award units	6	5
Diluted shares	922	915

XML

Stockholders' Equity - Changes in Stockholders' Equity (Details) - USD ($) shares in Thousands, $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Changes in Stockholders' Equity
Beginning Balance, Treasury Shares	(3,400)
Beginning Balance	$ 21,982	$ 20,926
Consolidated net income attributable to Southern Company	485	508
Other comprehensive income (loss)	(114)	(15)
Stock issued	270	112
Stock-based compensation	60	53
Stock repurchased, at cost		(115)
Cash dividends on common stock	(497)	(478)
Contributions from noncontrolling interests	129
Distributions to noncontrolling interests	(4)
Noncontrolling Interest, Decrease from Redemptions or Purchase of Interests	129
Payments to Noncontrolling Interests	4	0
Net income attributable to noncontrolling interests	1
Other	$ 1	3
Beginning Balance, Treasury Shares	(3,400)
Ending Balance	$ 22,184	$ 20,994
Number of Common shares Issued [Member]
Changes in Stockholders' Equity
Beginning Balance, Shares	915,073	908,502
Stock issued, Shares	6,572	3,094
Ending Balance, Shares	921,645	911,596
Number of Common shares Treasury [Member]
Changes in Stockholders' Equity
Beginning Balance, Treasury Shares	(3,352)	(725)
Stock repurchased, at cost, Shares		(2,599)
Other, Shares	(35)	(11)
Beginning Balance, Treasury Shares	(3,387)	(3,335)
Common Stockholders' Equity [Member]
Changes in Stockholders' Equity
Beginning Balance	$ 20,592	$ 19,949
Consolidated net income attributable to Southern Company	485	508
Other comprehensive income (loss)	(114)	(15)
Stock issued	270	112
Stock-based compensation	60	53
Stock repurchased, at cost		(115)
Cash dividends on common stock	(497)	(478)
Other	1	3
Ending Balance	20,797	20,017
Preferred And Preference Stock [Member]
Changes in Stockholders' Equity
Beginning Balance	609	756
Stock issued		0
Other	0
Ending Balance	609	756
Noncontrolling Interest [Member]
Changes in Stockholders' Equity
Beginning Balance	781	221
Contributions from noncontrolling interests	129
Distributions to noncontrolling interests	(4)
Noncontrolling Interest, Decrease from Redemptions or Purchase of Interests	129
Net income attributable to noncontrolling interests	1
Ending Balance	$ 778	$ 221

XML

Financing - Schedule of Credit Arrangements (Details) - USD ($)	Mar. 31, 2016	Sep. 30, 2015
Line of Credit Facility [Line Items]
Expires, 2016	$ 390,000,000
Expires, 2017	40,000,000
Expires, 2018	1,665,000,000
Expires, 2020	4,400,000,000
Total	6,495,000,000
Unused	6,412,000,000
Executable Term Loans, One Year	95,000,000
Executable Term Loans, Two Years	15,000,000
Due Within One Year, Term Out	110,000,000
Due Within One Year, No Term Out	290,000,000
Bridge Agreement [Member]
Line of Credit Facility [Line Items]
Total		$ 8,100,000,000
Southern Company [Member]
Line of Credit Facility [Line Items]
Expires, 2016	0
Expires, 2017	0
Expires, 2018	1,000,000,000
Expires, 2020	1,250,000,000
Total	2,250,000,000
Unused	2,250,000,000
Executable Term Loans, One Year	0
Executable Term Loans, Two Years	0
Due Within One Year, Term Out	0
Due Within One Year, No Term Out	0
Alabama Power [Member]
Line of Credit Facility [Line Items]
Expires, 2016	40,000,000
Expires, 2017	0
Expires, 2018	500,000,000
Expires, 2020	800,000,000
Total	1,340,000,000
Unused	1,340,000,000
Executable Term Loans, One Year	0
Executable Term Loans, Two Years	0
Due Within One Year, Term Out	0
Due Within One Year, No Term Out	40,000,000
Georgia Power [Member]
Line of Credit Facility [Line Items]
Expires, 2016	0
Expires, 2017	0
Expires, 2018	0
Expires, 2020	1,750,000,000
Total	1,750,000,000
Unused	1,732,000,000
Executable Term Loans, One Year	0
Executable Term Loans, Two Years	0
Due Within One Year, Term Out	0
Due Within One Year, No Term Out	0
Gulf Power [Member]
Line of Credit Facility [Line Items]
Expires, 2016	75,000,000
Expires, 2017	40,000,000
Expires, 2018	165,000,000
Expires, 2020	0
Total	280,000,000
Unused	280,000,000
Executable Term Loans, One Year	45,000,000
Executable Term Loans, Two Years	0
Due Within One Year, Term Out	45,000,000
Due Within One Year, No Term Out	40,000,000
Mississippi Power [Member]
Line of Credit Facility [Line Items]
Expires, 2016	205,000,000
Expires, 2017	0
Expires, 2018	0
Expires, 2020	0
Total	205,000,000
Unused	180,000,000
Executable Term Loans, One Year	30,000,000
Executable Term Loans, Two Years	15,000,000
Due Within One Year, Term Out	45,000,000
Due Within One Year, No Term Out	160,000,000
Southern Power [Member]
Line of Credit Facility [Line Items]
Expires, 2016	0
Expires, 2017	0
Expires, 2018	0
Expires, 2020	600,000,000
Total	600,000,000
Unused	560,000,000
Executable Term Loans, One Year	0
Executable Term Loans, Two Years	0
Due Within One Year, Term Out	0
Due Within One Year, No Term Out	0
Other [Member]
Line of Credit Facility [Line Items]
Expires, 2016	70,000,000
Expires, 2017	0
Expires, 2018	0
Expires, 2020	0
Total	70,000,000
Unused	70,000,000
Executable Term Loans, One Year	20,000,000
Executable Term Loans, Two Years	0
Due Within One Year, Term Out	20,000,000
Due Within One Year, No Term Out	$ 50,000,000

XML

Financing -Schedule of Line of Credit Facilities (Details)	Mar. 31, 2016 USD ($)
Line of Credit Facility [Line Items]
Maximum Borrowing Capacity	$ 6,495,000,000
Remaining Borrowing Capacity	6,412,000,000
Southern Power [Member]
Line of Credit Facility [Line Items]
Maximum Borrowing Capacity	600,000,000
Remaining Borrowing Capacity	560,000,000
Construction Loans [Member] | Southern Power [Member]
Line of Credit Facility [Line Items]
Maximum Borrowing Capacity	235,000,000
Construction Loans [Member] | Southern Power [Member] | RE Tranquility Holdings, LLC [Member]
Line of Credit Facility [Line Items]
Maximum Borrowing Capacity	86,000,000
Construction Loans [Member] | Southern Power [Member] | RE Roserock Holdings, LLC [Member]
Line of Credit Facility [Line Items]
Maximum Borrowing Capacity	63,000,000
Construction Loans [Member] | Southern Power [Member] | RE Garland Holdings, LLC [Member]
Line of Credit Facility [Line Items]
Maximum Borrowing Capacity	86,000,000
Bridge Loan [Member] | Southern Power [Member]
Line of Credit Facility [Line Items]
Maximum Borrowing Capacity	660,000,000
Bridge Loan [Member] | Southern Power [Member] | RE Tranquility Holdings, LLC [Member]
Line of Credit Facility [Line Items]
Maximum Borrowing Capacity	172,000,000
Bridge Loan [Member] | Southern Power [Member] | RE Roserock Holdings, LLC [Member]
Line of Credit Facility [Line Items]
Maximum Borrowing Capacity	180,000,000
Bridge Loan [Member] | Southern Power [Member] | RE Garland Holdings, LLC [Member]
Line of Credit Facility [Line Items]
Maximum Borrowing Capacity	308,000,000
Construction Loan And Bridge Loan [Member] | Southern Power [Member]
Line of Credit Facility [Line Items]
Maximum Borrowing Capacity	895,000,000
Remaining Borrowing Capacity	482,000,000
Construction Loan And Bridge Loan [Member] | Southern Power [Member] | RE Tranquility Holdings, LLC [Member]
Line of Credit Facility [Line Items]
Maximum Borrowing Capacity	258,000,000
Remaining Borrowing Capacity	52,000,000
Construction Loan And Bridge Loan [Member] | Southern Power [Member] | RE Roserock Holdings, LLC [Member]
Line of Credit Facility [Line Items]
Maximum Borrowing Capacity	243,000,000
Remaining Borrowing Capacity	121,000,000
Construction Loan And Bridge Loan [Member] | Southern Power [Member] | RE Garland Holdings, LLC [Member]
Line of Credit Facility [Line Items]
Maximum Borrowing Capacity	394,000,000
Remaining Borrowing Capacity	309,000,000
Letter of Credit [Member] | Southern Power [Member]
Line of Credit Facility [Line Items]
Maximum Borrowing Capacity	149,000,000
Remaining Borrowing Capacity	74,000,000
Letter of Credit [Member] | Southern Power [Member] | RE Tranquility Holdings, LLC [Member]
Line of Credit Facility [Line Items]
Maximum Borrowing Capacity	77,000,000
Remaining Borrowing Capacity	26,000,000
Letter of Credit [Member] | Southern Power [Member] | RE Roserock Holdings, LLC [Member]
Line of Credit Facility [Line Items]
Maximum Borrowing Capacity	23,000,000
Remaining Borrowing Capacity	16,000,000
Letter of Credit [Member] | Southern Power [Member] | RE Garland Holdings, LLC [Member]
Line of Credit Facility [Line Items]
Maximum Borrowing Capacity	49,000,000
Remaining Borrowing Capacity	$ 32,000,000

XML

Financing - Schedule of Long-Term Debt Financing Activities (Details) $ in Millions	3 Months Ended
	Mar. 31, 2016 USD ($)
Debt Instrument [Line Items]
Senior Note Issuances	$ 1,050
Senior Note Maturities and Redemptions	450
Revenue Bond Maturities Redemptions and Repurchases	4
Other Long-Term Debt Issuances	947
Other Long-Term Debt Redemptions and Maturities	434
Consolidation, Eliminations [Member]
Debt Instrument [Line Items]
Other Long-Term Debt Issuances	(200)
Alabama Power [Member]
Debt Instrument [Line Items]
Senior Note Issuances	400
Senior Note Maturities and Redemptions	200
Revenue Bond Maturities Redemptions and Repurchases	0
Other Long-Term Debt Issuances	45
Other Long-Term Debt Redemptions and Maturities	0
Georgia Power [Member]
Debt Instrument [Line Items]
Senior Note Issuances	650
Senior Note Maturities and Redemptions	250
Revenue Bond Maturities Redemptions and Repurchases	4
Other Long-Term Debt Issuances	0
Other Long-Term Debt Redemptions and Maturities	1
Mississippi Power [Member]
Debt Instrument [Line Items]
Senior Note Issuances	0
Senior Note Maturities and Redemptions	0
Revenue Bond Maturities Redemptions and Repurchases	0
Other Long-Term Debt Issuances	1,100
Other Long-Term Debt Redemptions and Maturities	426
Southern Power [Member]
Debt Instrument [Line Items]
Senior Note Issuances	0
Senior Note Maturities and Redemptions	0
Revenue Bond Maturities Redemptions and Repurchases	0
Other Long-Term Debt Issuances	2
Other Long-Term Debt Redemptions and Maturities	3
Other [Member]
Debt Instrument [Line Items]
Senior Note Issuances	0
Senior Note Maturities and Redemptions	0
Revenue Bond Maturities Redemptions and Repurchases	0
Other Long-Term Debt Issuances	0
Other Long-Term Debt Redemptions and Maturities	$ 4

XML

Financing - Narrative (Details) - USD ($)	1 Months Ended	3 Months Ended
	Jan. 31, 2016	Mar. 31, 2016	Mar. 14, 2016	Mar. 08, 2016	Jan. 29, 2016	Jan. 19, 2016	Sep. 30, 2015
Debt Instrument [Line Items]
Amount of Variable Rate Pollution Control Revenue Bonds Outstanding Requiring Liquidity Support		$ 1,800,000,000
Maximum Borrowing Capacity		6,495,000,000
Remaining Borrowing Capacity		6,412,000,000
Bridge Agreement [Member]
Debt Instrument [Line Items]
Maximum Borrowing Capacity							$ 8,100,000,000
Scenario, Plan [Member] | Bridge Agreement [Member]
Debt Instrument [Line Items]
Expected Debt Issuance (minimum)		8,000,000,000
Expected Equity Issuance (maximum)		1,200,000,000
Alabama Power [Member]
Debt Instrument [Line Items]
Amount of Variable Rate Pollution Control Revenue Bonds Outstanding Requiring Liquidity Support		810,000,000
Amount of Fixed Rate Pollution Control Revenue Bonds Outstanding Requiring Liquidity Support		167,000,000
Maximum Borrowing Capacity		1,340,000,000
Remaining Borrowing Capacity		1,340,000,000
Alabama Power [Member] | Series FF [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	5.20%
Alabama Power [Member] | Senior Notes [Member] | Series 2016A [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 400,000,000
Debt Instrument, Interest Rate, Stated Percentage	4.30%
Alabama Power [Member] | Unsecured Debt [Member] | Series FF [Member]
Debt Instrument [Line Items]
Redemption Amount Of Principal Notes	$ 200,000,000
Alabama Power [Member] | Bank Loans [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount		$ 45,000,000
Debt Instrument, Interest Rate, Stated Percentage		2.38%
Georgia Power [Member]
Debt Instrument [Line Items]
Amount of Variable Rate Pollution Control Revenue Bonds Outstanding Requiring Liquidity Support		$ 868,000,000
Amount of Fixed Rate Pollution Control Revenue Bonds Outstanding Requiring Liquidity Support		69,000,000
Maximum Borrowing Capacity		1,750,000,000
Remaining Borrowing Capacity		1,732,000,000
Georgia Power [Member] | Senior Notes [Member] | Series 2016A [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount		$ 325,000,000
Debt Instrument, Interest Rate, Stated Percentage		3.25%
Georgia Power [Member] | Senior Notes [Member] | Series 2016B [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount		$ 325,000,000
Debt Instrument, Interest Rate, Stated Percentage		2.40%
Georgia Power [Member] | Unsecured Debt [Member] | Series 2013B [Member]
Debt Instrument [Line Items]
Redemption Amount Of Principal Notes		$ 250,000,000
Gulf Power [Member]
Debt Instrument [Line Items]
Amount of Variable Rate Pollution Control Revenue Bonds Outstanding Requiring Liquidity Support		82,000,000
Amount of Fixed Rate Pollution Control Revenue Bonds Outstanding Requiring Liquidity Support		33,000,000
Maximum Borrowing Capacity		280,000,000
Remaining Borrowing Capacity		280,000,000
Mississippi Power [Member]
Debt Instrument [Line Items]
Amount of Variable Rate Pollution Control Revenue Bonds Outstanding Requiring Liquidity Support		40,000,000
Maximum Borrowing Capacity		205,000,000
Line of Credit Facility, Current Borrowing Capacity		100,000,000	$ 50,000,000		$ 50,000,000	$ 100,000,000
Promissory Note	$ 275,000,000
Remaining Borrowing Capacity		180,000,000
Mississippi Power [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Redemption Amount Of Principal Notes				$ 300,000,000
Mississippi Power [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Maximum Borrowing Capacity				1,200,000,000
Line of Credit Facility, Current Borrowing Capacity				900,000,000
Remaining Borrowing Capacity				300,000,000
Mississippi Power [Member] | Notes Payable to Banks [Member]
Debt Instrument [Line Items]
Redemption Amount Of Principal Notes				$ 900,000,000
Mississippi Power [Member] | Notes Payable, Other Payables [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount		10,000,000
Traditional Operating Companies [Member]
Debt Instrument [Line Items]
Amount of Fixed Rate Pollution Control Revenue Bonds Outstanding Requiring Liquidity Support		269,000,000
Southern Company [Member]
Debt Instrument [Line Items]
Maximum Borrowing Capacity		2,250,000,000
Remaining Borrowing Capacity		2,250,000,000
Southern Power [Member]
Debt Instrument [Line Items]
Maximum Borrowing Capacity		600,000,000
Line of Credit Facility, Current Borrowing Capacity		$ 276,000,000
Debt, Weighted Average Interest Rate		1.99%
Remaining Borrowing Capacity		$ 560,000,000
Early Repayment of Senior Debt		3,000,000
Southern Power [Member] | TRE Debt Due 2036 [Member]
Debt Instrument [Line Items]
Promissory Note		2,000,000
Southern Power [Member] | Project Credit Facilities [Member]
Debt Instrument [Line Items]
Maximum Borrowing Capacity		413,000,000
Line of Credit Facility, Current Borrowing Capacity		$ 413,000,000
Debt, Weighted Average Interest Rate		1.99%
Line of Credit Facility, Average Amount Outstanding		$ 260,000,000
Southern Power [Member] | Letter of Credit [Member]
Debt Instrument [Line Items]
Maximum Borrowing Capacity		149,000,000
Line of Credit Facility, Current Borrowing Capacity		8,000,000
Remaining Borrowing Capacity		$ 74,000,000

XML

Retirement Benefits (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Pension Plans [Member] | Southern Company [Member]
Pension Plans and Postretirement Plans
Service cost	$ 62	$ 64
Interest cost	100	111
Expected return on plan assets	(187)	(181)
Amortization:
Prior service costs	4	6
Net (gain)/loss	38	54
Net cost	17	54
Pension Plans [Member] | Alabama Power [Member]
Pension Plans and Postretirement Plans
Service cost	14	15
Interest cost	24	26
Expected return on plan assets	(46)	(45)
Amortization:
Prior service costs	1	2
Net (gain)/loss	10	14
Net cost	3	12
Pension Plans [Member] | Georgia Power [Member]
Pension Plans and Postretirement Plans
Service cost	17	18
Interest cost	34	38
Expected return on plan assets	(64)	(63)
Amortization:
Prior service costs	1	3
Net (gain)/loss	14	19
Net cost	2	15
Pension Plans [Member] | Gulf Power [Member]
Pension Plans and Postretirement Plans
Service cost	3	3
Interest cost	5	5
Expected return on plan assets	(9)	(8)
Amortization:
Prior service costs	0	0
Net (gain)/loss	2	3
Net cost	1	3
Pension Plans [Member] | Mississippi Power [Member]
Pension Plans and Postretirement Plans
Service cost	3	3
Interest cost	5	5
Expected return on plan assets	(9)	(8)
Amortization:
Prior service costs	0	0
Net (gain)/loss	2	3
Net cost	1	3
Other Postretirement Benefits [Member] | Southern Company [Member]
Pension Plans and Postretirement Plans
Service cost	5	6
Interest cost	18	19
Expected return on plan assets	(14)	(15)
Amortization:
Prior service costs	2	1
Net (gain)/loss	3	5
Net cost	14	16
Other Postretirement Benefits [Member] | Alabama Power [Member]
Pension Plans and Postretirement Plans
Service cost	1	1
Interest cost	5	5
Expected return on plan assets	(6)	(6)
Amortization:
Prior service costs	1	1
Net (gain)/loss	0	0
Net cost	1	1
Other Postretirement Benefits [Member] | Georgia Power [Member]
Pension Plans and Postretirement Plans
Service cost	2	2
Interest cost	8	8
Expected return on plan assets	(6)	(6)
Amortization:
Prior service costs	0	0
Net (gain)/loss	2	3
Net cost	6	7
Other Postretirement Benefits [Member] | Gulf Power [Member]
Pension Plans and Postretirement Plans
Service cost	0	0
Interest cost	1	1
Expected return on plan assets	0	0
Amortization:
Prior service costs	0	0
Net (gain)/loss	0	0
Net cost	1	1
Other Postretirement Benefits [Member] | Mississippi Power [Member]
Pension Plans and Postretirement Plans
Service cost	0	0
Interest cost	1	1
Expected return on plan assets	0	0
Amortization:
Prior service costs	0	0
Net (gain)/loss	0	0
Net cost	$ 1	$ 1

XML

Income Taxes (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
Income Tax Contingency [Line Items]
Effective tax rate	30.80%	34.30%
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized tax benefits as of December 31, 2015	$ 433
Tax positions from current periods	5
Balance as of March 31, 2016	438
Tax positions impacting the effective tax rate	15		$ 10
Tax positions not impacting the effective tax rate	423		423
Kemper IGCC [Member]
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance as of March 31, 2016	423
Unrecognized tax benefit, associated interest	$ 12
Mississippi Power [Member]
Income Tax Contingency [Line Items]
Effective tax rate	(838.70%)	10.00%
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized tax benefits as of December 31, 2015	$ 421
Tax positions from current periods	0
Balance as of March 31, 2016	421
Tax positions impacting the effective tax rate	(2)
Tax positions not impacting the effective tax rate	423
Mississippi Power [Member] | Kemper IGCC [Member]
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance as of March 31, 2016	423
Unrecognized tax benefit, associated interest	12
Southern Power [Member]
Income Tax Contingency [Line Items]
Operating loss carryforwards	$ 694		$ 551
Effective tax rate	(84.00%)	25.80%
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized tax benefits as of December 31, 2015	$ 8
Tax positions from current periods	5
Balance as of March 31, 2016	13
Tax positions impacting the effective tax rate	13
Tax positions not impacting the effective tax rate	$ 0

XML

Derivatives - Schedule of Derivatives and Gains (Losses) (Details) BTU in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2016 USD ($) BTU
Notional amount of interest rate derivatives
Notional Amount	$ 4,657
Fair Value Gain (Loss) at March 31, 2016	(161)
Southern Company [Member] | Maturity Date November 2026 [Member] | Cash Flow Hedges Of Forecasted Debt [Member]
Notional amount of interest rate derivatives
Notional Amount	$ 1,500
Weighted Average Interest Rate Paid	2.14%
Fair Value Gain (Loss) at March 31, 2016	$ (55)
Southern Company [Member] | Maturity Date November 2046 [Member] | Cash Flow Hedges Of Forecasted Debt [Member]
Notional amount of interest rate derivatives
Notional Amount	$ 1,200
Weighted Average Interest Rate Paid	2.60%
Fair Value Gain (Loss) at March 31, 2016	$ (127)
Southern Company [Member] | Maturity Date August 2017 [Member] | Fair Value Hedges Of Existing Debt [Member]
Notional amount of interest rate derivatives
Notional Amount	$ 250
Interest Rate Received	1.30%
Fair Value Gain (Loss) at March 31, 2016	$ 1
Southern Company [Member] | Maturity Date August 2017 [Member] | London Interbank Offered Rate (LIBOR) [Member] | Fair Value Hedges Of Existing Debt [Member]
Notional amount of interest rate derivatives
Weighted Average Interest Rate Paid	0.17%
Southern Company [Member] | Maturity Date June 2020 [Member] | Fair Value Hedges Of Existing Debt [Member]
Notional amount of interest rate derivatives
Notional Amount	$ 300
Interest Rate Received	2.75%
Fair Value Gain (Loss) at March 31, 2016	$ 10
Southern Company [Member] | Maturity Date June 2020 [Member] | London Interbank Offered Rate (LIBOR) [Member] | Fair Value Hedges Of Existing Debt [Member]
Notional amount of interest rate derivatives
Weighted Average Interest Rate Paid	0.92%
Southern Company [Member] | Gas [Member]
Energy-related derivative contracts
Net Purchased mmBtu | BTU	235
Longest Hedge Date	2020
Longest Non-Hedge Date	2017
Alabama Power [Member] | Gas [Member]
Energy-related derivative contracts
Net Purchased mmBtu | BTU	60
Longest Hedge Date	2019
Georgia Power [Member] | Maturity Date August 2016 [Member] | Cash Flow Hedges Of Existing Debt [Member]
Notional amount of interest rate derivatives
Notional Amount	$ 200
Weighted Average Interest Rate Paid	1.01%
Fair Value Gain (Loss) at March 31, 2016	$ 0
Georgia Power [Member] | Maturity Date August 2016 [Member] | London Interbank Offered Rate (LIBOR) [Member] | Cash Flow Hedges Of Existing Debt [Member]
Notional amount of interest rate derivatives
Interest Rate Received	0.40%
Georgia Power [Member] | Maturity Date June 2018 [Member] | Fair Value Hedges Of Existing Debt [Member]
Notional amount of interest rate derivatives
Notional Amount	$ 250
Interest Rate Received	5.40%
Fair Value Gain (Loss) at March 31, 2016	$ 3
Georgia Power [Member] | Maturity Date June 2018 [Member] | London Interbank Offered Rate (LIBOR) [Member] | Fair Value Hedges Of Existing Debt [Member]
Notional amount of interest rate derivatives
Weighted Average Interest Rate Paid	4.02%
Georgia Power [Member] | Maturity Date December 2019 [Member] | Fair Value Hedges Of Existing Debt [Member]
Notional amount of interest rate derivatives
Notional Amount	$ 200
Interest Rate Received	4.25%
Fair Value Gain (Loss) at March 31, 2016	$ 6
Georgia Power [Member] | Maturity Date December 2019 [Member] | London Interbank Offered Rate (LIBOR) [Member] | Fair Value Hedges Of Existing Debt [Member]
Notional amount of interest rate derivatives
Weighted Average Interest Rate Paid	2.46%
Georgia Power [Member] | Maturity Date December 2018 [Member] | Fair Value Hedges Of Existing Debt [Member]
Notional amount of interest rate derivatives
Notional Amount	$ 500
Interest Rate Received	1.95%
Fair Value Gain (Loss) at March 31, 2016	$ 5
Georgia Power [Member] | Maturity Date December 2018 [Member] | London Interbank Offered Rate (LIBOR) [Member] | Fair Value Hedges Of Existing Debt [Member]
Notional amount of interest rate derivatives
Weighted Average Interest Rate Paid	0.76%
Georgia Power [Member] | Gas [Member]
Energy-related derivative contracts
Net Purchased mmBtu | BTU	65
Longest Hedge Date	2019
Gulf Power [Member] | Maturity Date December 2026 [Member] | Cash Flow Hedges Of Forecasted Debt [Member]
Notional amount of interest rate derivatives
Notional Amount	$ 80
Weighted Average Interest Rate Paid	2.32%
Fair Value Gain (Loss) at March 31, 2016	$ (4)
Gulf Power [Member] | Gas [Member]
Energy-related derivative contracts
Net Purchased mmBtu | BTU	74
Longest Hedge Date	2020
Mississippi Power [Member] | Gas [Member]
Energy-related derivative contracts
Net Purchased mmBtu | BTU	28
Longest Hedge Date	2018
Southern Power [Member] | Maturity Date October 2016 [Member] | Not Designated as Hedging Instrument [Member]
Notional amount of interest rate derivatives
Notional Amount	$ 65
Weighted Average Interest Rate Paid	2.50%
Fair Value Gain (Loss) at March 31, 2016	$ 0
Derivative, Term of Contract	15 years
Southern Power [Member] | Maturity Date November 2016 [Member] | Not Designated as Hedging Instrument [Member]
Notional amount of interest rate derivatives
Derivative, Term of Contract	12 years
Southern Power [Member] | Gas [Member]
Energy-related derivative contracts
Net Purchased mmBtu | BTU	8
Longest Hedge Date	2016
Longest Non-Hedge Date	2017
RE Roserock Holdings, LLC [Member] | Southern Power [Member] | Maturity Date October 2016 [Member] | Not Designated as Hedging Instrument [Member]
Notional amount of interest rate derivatives
Notional Amount	$ 47
Weighted Average Interest Rate Paid	2.21%
Fair Value Gain (Loss) at March 31, 2016	$ 0
RE Garland and Garland A Holdings, LLC [Member] | Southern Power [Member] | Maturity Date November 2016 [Member] | Not Designated as Hedging Instrument [Member]
Notional amount of interest rate derivatives
Notional Amount	$ 65
Weighted Average Interest Rate Paid	2.21%
Fair Value Gain (Loss) at March 31, 2016	$ 0

XML

Derivatives - Balance Sheet Presentation (Details) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Southern Company [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	$ 45	$ 29
Derivatives, liabilities	394	250
Southern Company [Member] | Not Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	2	4
Southern Company [Member] | Not Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	1	1
Southern Company [Member] | Not Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	1	1
Southern Company [Member] | Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	1	3
Southern Company [Member] | Hedging Instruments for Regulatory Purposes [Member] | Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	7
Derivatives, liabilities	198	217
Southern Company [Member] | Hedging Instruments for Regulatory Purposes [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	2	3
Southern Company [Member] | Hedging Instruments for Regulatory Purposes [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other deferred charges and assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	5
Southern Company [Member] | Hedging Instruments for Regulatory Purposes [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	124	130
Southern Company [Member] | Hedging Instruments for Regulatory Purposes [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other deferred credits and liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	74	87
Southern Company [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	36	22
Derivatives, liabilities	195	32
Southern Company [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	4	3
Southern Company [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	2	2
Southern Company [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	18	19
Southern Company [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other deferred charges and assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	14
Southern Company [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	193	23
Southern Company [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other deferred credits and liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities		7
Alabama Power [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	3	1
Derivatives, liabilities	49	70
Alabama Power [Member] | Not Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
Alabama Power [Member] | Not Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
Alabama Power [Member] | Not Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	0	0
Alabama Power [Member] | Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
Alabama Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	3
Derivatives, liabilities	49	55
Alabama Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	1	1
Alabama Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other deferred charges and assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	2
Alabama Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	37	40
Alabama Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other deferred credits and liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	12	15
Alabama Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
Derivatives, liabilities	0	15
Alabama Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
Alabama Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	0	0
Alabama Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
Alabama Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other deferred charges and assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	0
Alabama Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	0	15
Alabama Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other deferred credits and liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities		0
Georgia Power [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	18	7
Derivatives, liabilities	11	21
Georgia Power [Member] | Not Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
Georgia Power [Member] | Not Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
Georgia Power [Member] | Not Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	0	0
Georgia Power [Member] | Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
Georgia Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	4
Derivatives, liabilities	11	15
Georgia Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	1	2
Georgia Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other deferred charges and assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	3
Georgia Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	9	12
Georgia Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other deferred credits and liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	2	3
Georgia Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	14	5
Derivatives, liabilities	0	6
Georgia Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
Georgia Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	0	0
Georgia Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	7	5
Georgia Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other deferred charges and assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	7
Georgia Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	0	0
Georgia Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other deferred credits and liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities		6
Gulf Power [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	1
Derivatives, liabilities	99	100
Gulf Power [Member] | Not Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
Gulf Power [Member] | Not Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
Gulf Power [Member] | Not Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	0	0
Gulf Power [Member] | Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
Gulf Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	0
Derivatives, liabilities	94	100
Gulf Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
Gulf Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other deferred charges and assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	0
Gulf Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	49	49
Gulf Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other deferred credits and liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	45	51
Gulf Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	1
Derivatives, liabilities	5	0
Gulf Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
Gulf Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	0	0
Gulf Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	1
Gulf Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other deferred charges and assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	0
Gulf Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	5	0
Gulf Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other deferred credits and liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities		0
Mississippi Power [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
Derivatives, liabilities	44	47
Mississippi Power [Member] | Not Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
Mississippi Power [Member] | Not Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
Mississippi Power [Member] | Not Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	0	0
Mississippi Power [Member] | Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
Mississippi Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	0
Derivatives, liabilities	44	47
Mississippi Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
Mississippi Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other deferred charges and assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	0
Mississippi Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	29	29
Mississippi Power [Member] | Hedging Instruments for Regulatory Purposes [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other deferred credits and liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	15	18
Mississippi Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
Derivatives, liabilities	0	0
Mississippi Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
Mississippi Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	0	0
Mississippi Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
Mississippi Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other deferred charges and assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	0
Mississippi Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	0	0
Mississippi Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other deferred credits and liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities		0
Southern Power [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	6	7
Derivatives, liabilities	3	3
Southern Power [Member] | Not Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	2	4
Southern Power [Member] | Not Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	1	1
Southern Power [Member] | Not Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	1	1
Southern Power [Member] | Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	1	3
Southern Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	4	3
Derivatives, liabilities	2	2
Southern Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	4	3
Southern Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Energy Related Derivative [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	2	2
Southern Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other current assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
Southern Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other deferred charges and assets [Member]
Derivatives, Fair Value [Line Items]
Derivatives, assets	0
Southern Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Liabilities from risk management activities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	$ 0	0
Southern Power [Member] | Cash Flow and Fair Value Hedging [Member] | Designated as Hedging Instrument [Member] | Interest Rate Contract [Member] | Other deferred credits and liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivatives, liabilities		$ 0

XML

Derivatives - Balance Sheet Offsetting (Details) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Southern Company [Member]
Derivative [Line Items]
Derivatives presented in the Balance Sheet, assets	$ 45	$ 29
Derivatives presented in the Balance Sheet, liabilities	394	250
Southern Company [Member] | Energy Related Derivative [Member]
Derivative [Line Items]
Net derivative assets	2	1
Net interest rate derivative liabilities	191	214
Southern Company [Member] | Energy Related Derivative [Member] | Net Amount Of Derivatives [Member]
Derivative [Line Items]
Derivatives presented in the Balance Sheet, assets	12	7
Derivatives presented in the Balance Sheet, liabilities	201	220
Southern Company [Member] | Energy Related Derivative [Member] | Gross Amount Of Derivatives [Member]
Derivative [Line Items]
Gross amounts not offset in the Balance Sheet, assets	(10)	(6)
Gross amounts not offset in the Balance Sheet, liabilities	(10)	(6)
Southern Company [Member] | Interest Rate Contract [Member]
Derivative [Line Items]
Net derivative assets	12	13
Net interest rate derivative liabilities	172	21
Southern Company [Member] | Interest Rate Contract [Member] | Net Amount Of Derivatives [Member]
Derivative [Line Items]
Derivatives presented in the Balance Sheet, assets	33	22
Derivatives presented in the Balance Sheet, liabilities	193	30
Southern Company [Member] | Interest Rate Contract [Member] | Gross Amount Of Derivatives [Member]
Derivative [Line Items]
Gross amounts not offset in the Balance Sheet, assets	(21)	(9)
Gross amounts not offset in the Balance Sheet, liabilities	(21)	(9)
Alabama Power [Member]
Derivative [Line Items]
Derivatives presented in the Balance Sheet, assets	3	1
Derivatives presented in the Balance Sheet, liabilities	49	70
Alabama Power [Member] | Energy Related Derivative [Member]
Derivative [Line Items]
Net derivative assets	0	0
Net interest rate derivative liabilities	46	54
Alabama Power [Member] | Energy Related Derivative [Member] | Net Amount Of Derivatives [Member]
Derivative [Line Items]
Derivatives presented in the Balance Sheet, assets	3	1
Derivatives presented in the Balance Sheet, liabilities	49	55
Alabama Power [Member] | Energy Related Derivative [Member] | Gross Amount Of Derivatives [Member]
Derivative [Line Items]
Gross amounts not offset in the Balance Sheet, assets	(3)	(1)
Gross amounts not offset in the Balance Sheet, liabilities	(3)	(1)
Alabama Power [Member] | Interest Rate Contract [Member]
Derivative [Line Items]
Net derivative assets	0	0
Net interest rate derivative liabilities	0	15
Alabama Power [Member] | Interest Rate Contract [Member] | Net Amount Of Derivatives [Member]
Derivative [Line Items]
Derivatives presented in the Balance Sheet, assets	0	0
Derivatives presented in the Balance Sheet, liabilities	0	15
Alabama Power [Member] | Interest Rate Contract [Member] | Gross Amount Of Derivatives [Member]
Derivative [Line Items]
Gross amounts not offset in the Balance Sheet, assets	0	0
Gross amounts not offset in the Balance Sheet, liabilities	0	0
Georgia Power [Member]
Derivative [Line Items]
Derivatives presented in the Balance Sheet, assets	18	7
Derivatives presented in the Balance Sheet, liabilities	11	21
Georgia Power [Member] | Energy Related Derivative [Member]
Derivative [Line Items]
Net derivative assets	1	0
Net interest rate derivative liabilities	8	13
Georgia Power [Member] | Energy Related Derivative [Member] | Net Amount Of Derivatives [Member]
Derivative [Line Items]
Derivatives presented in the Balance Sheet, assets	4	2
Derivatives presented in the Balance Sheet, liabilities	11	15
Georgia Power [Member] | Energy Related Derivative [Member] | Gross Amount Of Derivatives [Member]
Derivative [Line Items]
Gross amounts not offset in the Balance Sheet, assets	(3)	(2)
Gross amounts not offset in the Balance Sheet, liabilities	(3)	(2)
Georgia Power [Member] | Interest Rate Contract [Member]
Derivative [Line Items]
Net derivative assets	14	1
Net interest rate derivative liabilities	0	2
Georgia Power [Member] | Interest Rate Contract [Member] | Net Amount Of Derivatives [Member]
Derivative [Line Items]
Derivatives presented in the Balance Sheet, assets	14	5
Derivatives presented in the Balance Sheet, liabilities	0	6
Georgia Power [Member] | Interest Rate Contract [Member] | Gross Amount Of Derivatives [Member]
Derivative [Line Items]
Gross amounts not offset in the Balance Sheet, assets	0	(4)
Gross amounts not offset in the Balance Sheet, liabilities	0	(4)
Gulf Power [Member]
Derivative [Line Items]
Derivatives presented in the Balance Sheet, assets	0	1
Derivatives presented in the Balance Sheet, liabilities	99	100
Gulf Power [Member] | Energy Related Derivative [Member]
Derivative [Line Items]
Net derivative assets	0	0
Net interest rate derivative liabilities	94	100
Gulf Power [Member] | Energy Related Derivative [Member] | Net Amount Of Derivatives [Member]
Derivative [Line Items]
Derivatives presented in the Balance Sheet, assets	0	0
Derivatives presented in the Balance Sheet, liabilities	94	100
Gulf Power [Member] | Energy Related Derivative [Member] | Gross Amount Of Derivatives [Member]
Derivative [Line Items]
Gross amounts not offset in the Balance Sheet, assets	0	0
Gross amounts not offset in the Balance Sheet, liabilities	0	0
Gulf Power [Member] | Interest Rate Contract [Member]
Derivative [Line Items]
Net derivative assets	0	1
Net interest rate derivative liabilities	5	0
Gulf Power [Member] | Interest Rate Contract [Member] | Net Amount Of Derivatives [Member]
Derivative [Line Items]
Derivatives presented in the Balance Sheet, assets	0	1
Derivatives presented in the Balance Sheet, liabilities	5	0
Gulf Power [Member] | Interest Rate Contract [Member] | Gross Amount Of Derivatives [Member]
Derivative [Line Items]
Gross amounts not offset in the Balance Sheet, assets	0	0
Gross amounts not offset in the Balance Sheet, liabilities	0	0
Mississippi Power [Member]
Derivative [Line Items]
Derivatives presented in the Balance Sheet, assets	0	0
Derivatives presented in the Balance Sheet, liabilities	44	47
Mississippi Power [Member] | Energy Related Derivative [Member]
Derivative [Line Items]
Net derivative assets	0	0
Net interest rate derivative liabilities	44	47
Mississippi Power [Member] | Energy Related Derivative [Member] | Net Amount Of Derivatives [Member]
Derivative [Line Items]
Derivatives presented in the Balance Sheet, assets	0	0
Derivatives presented in the Balance Sheet, liabilities	44	47
Mississippi Power [Member] | Energy Related Derivative [Member] | Gross Amount Of Derivatives [Member]
Derivative [Line Items]
Gross amounts not offset in the Balance Sheet, assets	0	0
Gross amounts not offset in the Balance Sheet, liabilities	0	0
Mississippi Power [Member] | Interest Rate Contract [Member]
Derivative [Line Items]
Net derivative assets	0	0
Net interest rate derivative liabilities	0	0
Mississippi Power [Member] | Interest Rate Contract [Member] | Net Amount Of Derivatives [Member]
Derivative [Line Items]
Derivatives presented in the Balance Sheet, assets	0	0
Derivatives presented in the Balance Sheet, liabilities	0	0
Mississippi Power [Member] | Interest Rate Contract [Member] | Gross Amount Of Derivatives [Member]
Derivative [Line Items]
Gross amounts not offset in the Balance Sheet, assets	0	0
Gross amounts not offset in the Balance Sheet, liabilities	0	0
Southern Power [Member]
Derivative [Line Items]
Derivatives presented in the Balance Sheet, assets	6	7
Derivatives presented in the Balance Sheet, liabilities	3	3
Southern Power [Member] | Energy Related Derivative [Member]
Derivative [Line Items]
Net derivative assets	3	3
Net interest rate derivative liabilities	1	2
Southern Power [Member] | Energy Related Derivative [Member] | Net Amount Of Derivatives [Member]
Derivative [Line Items]
Derivatives presented in the Balance Sheet, assets	5	4
Derivatives presented in the Balance Sheet, liabilities	3	3
Southern Power [Member] | Energy Related Derivative [Member] | Gross Amount Of Derivatives [Member]
Derivative [Line Items]
Gross amounts not offset in the Balance Sheet, assets	(2)	(1)
Gross amounts not offset in the Balance Sheet, liabilities	(2)	(1)
Southern Power [Member] | Interest Rate Contract [Member]
Derivative [Line Items]
Net derivative assets	1	4
Net interest rate derivative liabilities	0	0
Southern Power [Member] | Interest Rate Contract [Member] | Net Amount Of Derivatives [Member]
Derivative [Line Items]
Derivatives presented in the Balance Sheet, assets	1	4
Derivatives presented in the Balance Sheet, liabilities	0	0
Southern Power [Member] | Interest Rate Contract [Member] | Gross Amount Of Derivatives [Member]
Derivative [Line Items]
Gross amounts not offset in the Balance Sheet, assets	0	0
Gross amounts not offset in the Balance Sheet, liabilities	$ 0	$ 0

XML

Derivatives - Pre-tax Effects of Derivatives Designated as Cash Flow Hedging Instruments (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
Southern Company [Member] | Energy Related Derivative [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet	$ (191)		$ (214)
Southern Company [Member] | Energy Related Derivative [Member] | Other regulatory assets, current [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet	(124)		(130)
Southern Company [Member] | Energy Related Derivative [Member] | Other regulatory assets, deferred [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet	(74)		(87)
Southern Company [Member] | Energy Related Derivative [Member] | Other regulatory liabilities, current [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet	2		3
Southern Company [Member] | Energy Related Derivative [Member] | Other regulatory liabilities, deferred [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet	5
Southern Company [Member] | Interest Rate Contract [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)	(190)	$ (29)
Southern Company [Member] | Interest Rate Contract [Member] | Interest Expense [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	(3)	(2)
Alabama Power [Member] | Energy Related Derivative [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet	(46)		(54)
Alabama Power [Member] | Energy Related Derivative [Member] | Other regulatory assets, current [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet	(37)		(40)
Alabama Power [Member] | Energy Related Derivative [Member] | Other regulatory assets, deferred [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet	(12)		(15)
Alabama Power [Member] | Energy Related Derivative [Member] | Other regulatory liabilities, current [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet	1		1
Alabama Power [Member] | Energy Related Derivative [Member] | Other regulatory liabilities, deferred [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet	2
Alabama Power [Member] | Interest Rate Contract [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)	(4)	(6)
Alabama Power [Member] | Interest Rate Contract [Member] | Interest Expense [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	(1)	(1)
Georgia Power [Member] | Energy Related Derivative [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet	(7)		(13)
Georgia Power [Member] | Energy Related Derivative [Member] | Other regulatory assets, current [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet	(9)		(12)
Georgia Power [Member] | Energy Related Derivative [Member] | Other regulatory assets, deferred [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet	(2)		(3)
Georgia Power [Member] | Energy Related Derivative [Member] | Other regulatory liabilities, current [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet	1		2
Georgia Power [Member] | Energy Related Derivative [Member] | Other regulatory liabilities, deferred [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet	3
Georgia Power [Member] | Interest Rate Contract [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)	0	(23)
Georgia Power [Member] | Interest Rate Contract [Member] | Interest Expense [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	(1)	(1)
Gulf Power [Member] | Energy Related Derivative [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet	(94)		(100)
Gulf Power [Member] | Energy Related Derivative [Member] | Other regulatory assets, current [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet	(49)		(49)
Gulf Power [Member] | Energy Related Derivative [Member] | Other regulatory assets, deferred [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet	(45)		(51)
Gulf Power [Member] | Energy Related Derivative [Member] | Other regulatory liabilities, current [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet	0		0
Gulf Power [Member] | Energy Related Derivative [Member] | Other regulatory liabilities, deferred [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet	0
Gulf Power [Member] | Interest Rate Contract [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative (Effective Portion)	(5)	0
Gulf Power [Member] | Interest Rate Contract [Member] | Interest Expense [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	0	$ 0
Mississippi Power [Member] | Energy Related Derivative [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet	(44)		(47)
Mississippi Power [Member] | Energy Related Derivative [Member] | Other regulatory assets, current [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet	(29)		(29)
Mississippi Power [Member] | Energy Related Derivative [Member] | Other regulatory assets, deferred [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet	(15)		(18)
Mississippi Power [Member] | Energy Related Derivative [Member] | Other regulatory liabilities, current [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet	0		$ 0
Mississippi Power [Member] | Energy Related Derivative [Member] | Other regulatory liabilities, deferred [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory Hedge Unrealized Gain (Loss) Recognized on the Balance Sheet	$ 0

XML

Derivatives - Pre-tax Effects of Derivatives Designated as Fair Value Hedging Instruments (Details) - Interest Rate Contract [Member] - Interest Expense [Member] - Fair Value Hedging [Member] - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Southern Company [Member]
Derivative [Line Items]
Gain (Loss)	$ 20	$ 7
Georgia Power [Member]
Derivative [Line Items]
Gain (Loss)	$ 14	$ 6

XML

Derivatives - Narrative (Details) BTU in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2016 USD ($) BTU
Derivative [Line Items]
Maximum Potential Collateral Requirements Arising from Credit Risk Related Contingent Features | $	$ 49
Southern Company [Member]
Derivative [Line Items]
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints | BTU	4

XML

Acquisitions - Schedule of Acquisitions (Details) $ in Millions			3 Months Ended
	Apr. 08, 2016 USD ($) MW	Feb. 11, 2016 USD ($) MW	Dec. 31, 2016 USD ($) MW	Jun. 30, 2016 USD ($) MW	Mar. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)
Business Acquisition [Line Items]
Construction work in progress					$ 9,406	$ 9,082
Southern Power [Member]
Business Acquisition [Line Items]
Construction work in progress					1,535	1,137
Business Combination, Contingent Consideration, Liability					21	$ 36
Southern Power [Member] | 70SM1 8ME, LCC (Calipatria) [Member]
Business Acquisition [Line Items]
Approx. Nameplate Capacity, Solar (MW) | MW		20
Southern Power Percentage Ownership		90.00%
PPA Contract Period		20 years
Approx. Purchase Price		$ 51
Southern Power [Member] | East Pecos [Member]
Business Acquisition [Line Items]
Construction work in progress					41
Southern Power [Member] | East Pecos [Member] | Minimum [Member]
Business Acquisition [Line Items]
Estimated Future Construction Payments					200
Southern Power [Member] | East Pecos [Member] | Maximum [Member]
Business Acquisition [Line Items]
Estimated Future Construction Payments					220
Southern Power [Member] | Turner Renewable Energy [Member]
Business Acquisition [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share		10.00%
Southern Power and Turner Renewable Energy [Member] | 70SM1 8ME, LCC (Calipatria) [Member]
Business Acquisition [Line Items]
Approx. Purchase Price		$ 57
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment					58
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities, Accounts Payable					2
Business Combination, Contingent Consideration, Liability		$ 6
Scenario, Forecast [Member] | Southern Power [Member] | Grant Wind, LLC [Member]
Business Acquisition [Line Items]
Approx. Nameplate Capacity, Wind (MW) | MW	151
Southern Power Percentage Ownership	100.00%
PPA Contract Period	20 years
Approx. Purchase Price	$ 258
Scenario, Forecast [Member] | Southern Power [Member] | East Pecos [Member]
Business Acquisition [Line Items]
Approx. Nameplate Capacity, Solar (MW) | MW			120
Southern Power Percentage Ownership			100.00%
PPA Contract Period			15 years
Approx. Purchase Price			$ 41
Scenario, Forecast [Member] | Southern Power [Member] | Desert Stateline Holdings, LLC [Member]
Business Acquisition [Line Items]
Approx. Nameplate Capacity, Solar (MW) | MW				40
Southern Power Percentage Ownership				100.00%
PPA Contract Period				15 years
Approx. Purchase Price				$ 127
Property, Plant and Equipment [Member] | Southern Power and Turner Renewable Energy [Member] | 70SM1 8ME, LCC (Calipatria) [Member]
Business Acquisition [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets					$ 1
Subsequent Event [Member] | Southern Power [Member] | Grant Wind, LLC [Member]
Business Acquisition [Line Items]
Business Combination, Contingent Consideration, Liability	$ 23
Period Of Operation For Performance Testing And Production	10 years

XML

Acquisitions - Schedule of Construction Projects (Details) $ in Millions	3 Months Ended		10 Months Ended
	Dec. 31, 2016 USD ($) MW	Sep. 30, 2016 MW	Sep. 30, 2016 USD ($) MW	May. 05, 2016 MW	Mar. 31, 2016 MW	Mar. 29, 2016	Dec. 31, 2015 MW
Southern Power [Member] | Desert Stateline Holdings, LLC [Member]
Business Acquisition [Line Items]
Capacity Of Small Power Production Facility | MW					76		110
Southern Power Percentage Ownership						15.00%
Class A Membership Interest [Member] | Southern Power [Member] | Desert Stateline Holdings, LLC [Member]
Business Acquisition [Line Items]
Percentage Of Entitled Cash Distributions						66.00%
Class A Membership Interest [Member] | Southern Power [Member] | Tranquillity, Roserock, Garland and Garland A [Member]
Business Acquisition [Line Items]
Southern Power Percentage Ownership					100.00%
Percentage Of Entitled Cash Distributions					51.00%
Class B Membership Interest [Member] | First Solar [Member] | Desert Stateline Holdings, LLC [Member]
Business Acquisition [Line Items]
Percentage Of Entitled Cash Distributions						34.00%
Class B Membership Interest [Member] | First Solar [Member] | Tranquillity, Roserock, Garland and Garland A [Member]
Business Acquisition [Line Items]
Southern Power Percentage Ownership					100.00%
Class B Membership Interest [Member] | Recurrent Energy [Member] | Tranquillity, Roserock, Garland and Garland A [Member]
Business Acquisition [Line Items]
Percentage Of Entitled Cash Distributions					49.00%
Scenario, Forecast [Member] | Southern Power [Member] | Sandhills [Member]
Business Acquisition [Line Items]
Approx. Nameplate Capacity, Solar (MW) | MW	146
PPA Contract Period	25 years
Scenario, Forecast [Member] | Southern Power [Member] | Sandhills [Member] | Minimum [Member]
Business Acquisition [Line Items]
Estimated Construction Costs	$ 260
Scenario, Forecast [Member] | Southern Power [Member] | Sandhills [Member] | Maximum [Member]
Business Acquisition [Line Items]
Estimated Construction Costs	$ 280
Scenario, Forecast [Member] | Southern Power [Member] | Butler Solar LLC [Member]
Business Acquisition [Line Items]
Approx. Nameplate Capacity, Solar (MW) | MW	103
PPA Contract Period	30 years
Scenario, Forecast [Member] | Southern Power [Member] | Butler Solar LLC [Member] | Minimum [Member]
Business Acquisition [Line Items]
Estimated Construction Costs	$ 220
Scenario, Forecast [Member] | Southern Power [Member] | Butler Solar LLC [Member] | Maximum [Member]
Business Acquisition [Line Items]
Estimated Construction Costs	$ 230
Scenario, Forecast [Member] | Southern Power [Member] | RE Garland Holdings, LLC [Member] | Minimum [Member]
Business Acquisition [Line Items]
PPA Contract Period	15 years
Scenario, Forecast [Member] | Southern Power [Member] | RE Tranquility Holdings, LLC [Member]
Business Acquisition [Line Items]
Approx. Nameplate Capacity, Solar (MW) | MW	205
PPA Contract Period	18 years
Scenario, Forecast [Member] | Southern Power [Member] | RE Tranquility Holdings, LLC [Member] | Minimum [Member]
Business Acquisition [Line Items]
Estimated Construction Costs	$ 473
Scenario, Forecast [Member] | Southern Power [Member] | RE Tranquility Holdings, LLC [Member] | Maximum [Member]
Business Acquisition [Line Items]
Estimated Construction Costs	$ 493
Scenario, Forecast [Member] | Southern Power [Member] | Desert Stateline Holdings, LLC [Member]
Business Acquisition [Line Items]
Capacity Of Small Power Production Facility | MW		75	75
Approx. Nameplate Capacity, Solar (MW) | MW		299	299
PPA Contract Period			20 years
Scenario, Forecast [Member] | Southern Power [Member] | Desert Stateline Holdings, LLC [Member] | Minimum [Member]
Business Acquisition [Line Items]
Estimated Construction Costs			$ 1,200
Scenario, Forecast [Member] | Southern Power [Member] | Desert Stateline Holdings, LLC [Member] | Maximum [Member]
Business Acquisition [Line Items]
Estimated Construction Costs			$ 1,300
Scenario, Forecast [Member] | Southern Power [Member] | RE Garland and Garland A Holdings, LLC [Member]
Business Acquisition [Line Items]
Approx. Nameplate Capacity, Solar (MW) | MW	205
Scenario, Forecast [Member] | Southern Power [Member] | RE Garland and Garland A Holdings, LLC [Member] | Minimum [Member]
Business Acquisition [Line Items]
Estimated Construction Costs	$ 532
Scenario, Forecast [Member] | Southern Power [Member] | RE Garland and Garland A Holdings, LLC [Member] | Maximum [Member]
Business Acquisition [Line Items]
Estimated Construction Costs	$ 552
Scenario, Forecast [Member] | Southern Power [Member] | RE Roserock Holdings, LLC [Member]
Business Acquisition [Line Items]
Approx. Nameplate Capacity, Solar (MW) | MW	160
PPA Contract Period	20 years
Scenario, Forecast [Member] | Southern Power [Member] | RE Roserock Holdings, LLC [Member] | Minimum [Member]
Business Acquisition [Line Items]
Estimated Construction Costs	$ 333
Scenario, Forecast [Member] | Southern Power [Member] | RE Roserock Holdings, LLC [Member] | Maximum [Member]
Business Acquisition [Line Items]
Estimated Construction Costs	$ 353
Scenario, Forecast [Member] | Southern Power [Member] | RE Garland and Garland A Holdings, LLC [Member] | Maximum [Member]
Business Acquisition [Line Items]
PPA Contract Period		20 years
Subsequent Event [Member] | Southern Power [Member] | Desert Stateline Holdings, LLC [Member]
Business Acquisition [Line Items]
Capacity Of Small Power Production Facility | MW				38

XML

Acquisitions - Narrative (Details) - USD ($)			3 Months Ended
	Feb. 24, 2016	Aug. 23, 2015	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015
Business Acquisition [Line Items]
Maximum Borrowing Capacity			$ 6,495,000,000
Construction in Progress, Gross			9,406,000,000	$ 9,082,000,000
Bridge Agreement [Member]
Business Acquisition [Line Items]
Business Combination, Acquisition Related Costs			20,000,000
Maximum Borrowing Capacity					$ 8,100,000,000
Scenario, Plan [Member] | PowerSecure International, Inc. [Member]
Business Acquisition [Line Items]
Business Combination, Consideration Transferred, Equity Interests Issued and Issuable	$ 431,000,000
Business Acquisition, Share Price	$ 18.75
Scenario, Plan [Member] | Bridge Agreement [Member]
Business Acquisition [Line Items]
Approx. Purchase Price		$ 8,200,000,000
Business Combination, Consideration Transferred, Equity Interests Issued and Issuable		8,000,000,000
Business Combination, Acquisition Related Costs		$ 200,000,000
Southern Power [Member]
Business Acquisition [Line Items]
Maximum Borrowing Capacity			600,000,000
Total Cost			2,200,000,000
Construction in Progress, Gross			1,535,000,000	$ 1,137,000,000
Operating Expense [Member] | Bridge Agreement [Member]
Business Acquisition [Line Items]
Business Combination, Acquisition Related Costs			6,000,000
Other Income Expense Net [Member] | Bridge Agreement [Member]
Business Acquisition [Line Items]
Business Combination, Acquisition Related Costs			$ 14,000,000

XML

Segment and Related Information - Financial Data for Business Segments (Details) $ in Millions	3 Months Ended
	Mar. 31, 2016 USD ($) state	Mar. 31, 2015 USD ($)	Dec. 31, 2015 USD ($)
Segment Reporting Information [Line Items]
Number of States in which Entity Operates | state	4
Operating revenues	$ 3,965	$ 4,183
Segment net income (loss)	485	508
Total assets	78,735		$ 78,318
Kemper IGCC [Member]
Segment Reporting Information [Line Items]
Pre-Tax Charge To Income	53	9
After Tax Charge To Income	33	6
Electric Utilities [Member]
Segment Reporting Information [Line Items]
Operating revenues	3,954	4,172
Segment net income (loss)	514	510
Total assets	77,843		77,560
Intersegment Eliminations [Member] | Electric Utilities [Member]
Segment Reporting Information [Line Items]
Operating revenues	(103)	(124)
Segment net income (loss)	0	0
Total assets	(396)		(397)
Consolidation Eliminations [Member]
Segment Reporting Information [Line Items]
Operating revenues	(36)	(29)
Segment net income (loss)	(3)	(5)
Total assets	(1,178)		(1,061)
Traditional Operating Companies [Member] | Electric Utilities [Member]
Segment Reporting Information [Line Items]
Operating revenues	3,742	3,948
Segment net income (loss)	464	477
Total assets	69,240		69,052
Southern Power [Member]
Segment Reporting Information [Line Items]
Operating revenues	97	114
Southern Power [Member] | Electric Utilities [Member]
Segment Reporting Information [Line Items]
Operating revenues	315	348
Segment net income (loss)	50	33
Total assets	8,999		8,905
All Other [Member]
Segment Reporting Information [Line Items]
Operating revenues	47	40
Segment net income (loss)	(26)	$ 3
Total assets	$ 2,070		$ 1,819

XML

Segment and Related Information - Financial Data for Products and Services (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Revenue from External Customer [Line Items]
Electric Utilities' Revenues	$ 3,954	$ 4,172
Retail [Member]
Revenue from External Customer [Line Items]
Electric Utilities' Revenues	3,377	3,542
Wholesale [Member]
Revenue from External Customer [Line Items]
Electric Utilities' Revenues	396	467
Other [Member]
Revenue from External Customer [Line Items]
Electric Utilities' Revenues	$ 181	$ 163