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.

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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.

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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

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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

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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.

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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.

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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

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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

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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

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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.

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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

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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.

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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

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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

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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.

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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.

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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.

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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.

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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.

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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.

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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

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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

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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

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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

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$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

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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

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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.

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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

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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

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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.

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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

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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.

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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.

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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:

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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.

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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.

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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.

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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

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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.

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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.

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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

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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.

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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.

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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.

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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.

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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

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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

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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.

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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.

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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.

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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.

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SOUTHERN POWER COMPANY

AND SUBSIDIARY COMPANIES

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SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended March 31,
	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.

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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.

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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.

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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.

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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.

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	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.

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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

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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

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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.

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(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.

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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

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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.

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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.

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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

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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

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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.

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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.

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(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

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(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.

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(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

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(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.

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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

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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

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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.

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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

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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.

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(UNAUDITED)

(E) FINANCING

Bank Credit Arrangements

Bank credit arrangements provide liquidity support to the registrants' commercial paper borrowings and the traditional operating companies' 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.

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(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.

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(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,

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(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

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(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

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(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.

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(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

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(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

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(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.

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(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.

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(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."

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(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."

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(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."

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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.

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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.

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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.

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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.

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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

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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.

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(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

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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.

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(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