Alabama Power (ALP-PQ) 10-Q 2016 Q2 Quarterly report

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 June 30, 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
001-37803	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 June 30, 2016
The Southern Company	Par Value $5 Per Share	941,598,673
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

June 30, 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	40
	Condensed Statements of Comprehensive Income	40
	Condensed Statements of Cash Flows	41
	Condensed Balance Sheets	42
	Management's Discussion and Analysis of Financial Condition and Results of Operations	44
	Georgia Power Company
	Condensed Statements of Income	57
	Condensed Statements of Comprehensive Income	57
	Condensed Statements of Cash Flows	58
	Condensed Balance Sheets	59
	Management's Discussion and Analysis of Financial Condition and Results of Operations	61
	Gulf Power Company
	Condensed Statements of Income	78
	Condensed Statements of Comprehensive Income	78
	Condensed Statements of Cash Flows	79
	Condensed Balance Sheets	80
	Management's Discussion and Analysis of Financial Condition and Results of Operations	82
	Mississippi Power Company
	Condensed Statements of Income	95
	Condensed Statements of Comprehensive Income	95
	Condensed Statements of Cash Flows	96
	Condensed Balance Sheets	97
	Management's Discussion and Analysis of Financial Condition and Results of Operations	99
	Southern Power Company and Subsidiary Companies
	Condensed Consolidated Statements of Income	123
	Condensed Consolidated Statements of Comprehensive Income	123
	Condensed Consolidated Statements of Cash Flows	124
	Condensed Consolidated Balance Sheets	125
	Management's Discussion and Analysis of Financial Condition and Results of Operations	127
	Notes to the Condensed Financial Statements	139
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	38
Item 4.	Controls and Procedures	38

3

INDEX TO QUARTERLY REPORT ON FORM 10-Q

June 30, 2016

		Page Number
	PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	193
Item 1A.	Risk Factors	193
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	193
	Signatures	198

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
Alabama Power	Alabama Power Company
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
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
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 Southern Company Gas on the terms and subject to the conditions set forth in the Merger Agreement, with Southern Company Gas 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 August 23, 2015, among Southern Company, Southern Company Gas, 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 electric 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 agreements and contracts for differences that provide the owner of the renewable facility a certain fixed price for the electricity sold to the grid
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
SCS	Southern Company Services, Inc. (the Southern Company system service company)
SEC	U.S. Securities and Exchange Commission
SMEPA	South Mississippi Electric Power Association
Southern Company	The Southern Company
Southern Company Gas	Southern Company Gas (formerly known as AGL Resources Inc.)
Southern Company system	Southern Company, the traditional electric operating companies, Southern Power, Southern Electric Generating Company, Southern Nuclear, SCS, Southern Communications Services, Inc., and other subsidiaries as of June 30, 2016
Southern Nuclear	Southern Nuclear Operating Company, Inc.
Southern Power	Southern Power Company and its subsidiaries
traditional electric 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 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 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 and natural gas, 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 natural gas and other fuels;

• limits on pipeline capacity;

• 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 Southern Company Gas' natural gas distribution and storage 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 inherent risks involved in transporting and storing natural gas;

• 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 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 Southern Company Gas will be greater than expected, the ability to retain and hire key personnel and maintain relationships with customers, suppliers, or other business partners, and the diversion of management time on integration-related issues;

• 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 or Southern Company Gas' 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 or Southern Company Gas' business resulting from incidents affecting the U.S. electric grid, natural gas pipeline infrastructure, or operation of generating or storage 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 June 30,						For the Six Months Ended June 30,
	2016			2015			2016			2015
	(in millions)						(in millions)
Operating Revenues:
Retail revenues	$	3,748		$	3,714		$	7,124		$	7,256
Wholesale revenues	446			448			842			915
Other electric revenues	166			162			348			325
Other revenues	99			13			137			24
Total operating revenues	4,459			4,337			8,451			8,520
Operating Expenses:
Fuel	1,023			1,200			1,934			2,412
Purchased power	189			171			354			315
Cost of sales	58			—			77			—
Other operations and maintenance	1,099			1,100			2,206			2,222
Depreciation and amortization	569			500			1,110			987
Taxes other than income taxes	255			245			511			497
Estimated loss on Kemper IGCC	81			23			134			32
Total operating expenses	3,274			3,239			6,326			6,465
Operating Income	1,185			1,098			2,125			2,055
Other Income and (Expense):
Allowance for equity funds used during construction	45			39			98			102
Interest expense, net of amounts capitalized	(293		)	(180		)	(539		)	(393		)
Other income (expense), net	(29		)	(12		)	(57		)	(19		)
Total other income and (expense)	(277		)	(153		)	(498		)	(310		)
Earnings Before Income Taxes	908			945			1,627			1,745
Income taxes	272			302			494			576
Consolidated Net Income	636			643			1,133			1,169
Less:
Dividends on Preferred and Preference Stock of Subsidiaries	12			14			23			31
Net income attributable to noncontrolling interests	12			—			13			—
Consolidated Net Income Attributable to Southern Company	$	612		$	629		$	1,097		$	1,138
Common Stock Data:
Earnings per share (EPS) —
Basic EPS	$	0.65		$	0.69		$	1.19		$	1.25
Diluted EPS	$	0.65		$	0.69		$	1.18		$	1.25
Average number of shares of common stock outstanding (in millions)
Basic	934			909			925			910
Diluted	940			912			931			914
Cash dividends paid per share of common stock	$	0.5600		$	0.5425		$	1.1025		$	1.0675

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 June 30,					For the Six Months Ended June 30,
	2016			2015		2016			2015
	(in millions)					(in millions)
Consolidated Net Income	$	636		$	643	$	1,133		$	1,169
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(13), $12, $(85), and $1, respectively	(20		)	19		(137		)	1
Reclassification adjustment for amounts included in net income, net of tax of $10, $1, $11, and $2, respectively	16			2		18			3
Pension and other post retirement benefit plans:
Reclassification adjustment for amounts included in net income, net of tax of $-, $1, $1, and $2, respectively	1			1		2			3
Total other comprehensive income (loss)	(3		)	22		(117		)	7
Less:
Dividends on preferred and preference stock of subsidiaries	12			14		23			31
Comprehensive income attributable to noncontrolling interests	12			—		13			—
Consolidated Comprehensive Income Attributable to    Southern Company	$	609		$	651	$	980		$	1,145

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 Six Months Ended June 30,
	2016			2015
	(in millions)
Operating Activities:
Consolidated net income	$	1,133		$	1,169
Adjustments to reconcile consolidated net income to net cash provided from operating activities —
Depreciation and amortization, total	1,306			1,171
Deferred income taxes	279			783
Allowance for equity funds used during construction	(98		)	(102		)
Stock based compensation expense	69			66
Hedge settlements	(201		)	(3		)
Estimated loss on Kemper IGCC	134			32
Income taxes receivable, non-current	—			(444		)
Other, net	(69		)	(3		)
Changes in certain current assets and liabilities —
-Receivables	(197		)	(158		)
-Fossil fuel stock	70			136
-Other current assets	(53		)	(99		)
-Accounts payable	(71		)	(311		)
-Accrued taxes	74			(60		)
-Accrued compensation	(222		)	(269		)
-Mirror CWIP	—			82
-Other current liabilities	(39		)	117
Net cash provided from operating activities	2,115			2,107
Investing Activities:
Business acquisitions, net of cash acquired	(897		)	(408		)
Property additions	(3,486		)	(2,239		)
Investment in restricted cash	(8,608		)	—
Distribution of restricted cash	649			—
Nuclear decommissioning trust fund purchases	(585		)	(933		)
Nuclear decommissioning trust fund sales	580			928
Cost of removal, net of salvage	(99		)	(87		)
Change in construction payables, net	(260		)	56
Prepaid long-term service agreement	(82		)	(110		)
Other investing activities	113			27
Net cash used for investing activities	(12,675		)	(2,766		)
Financing Activities:
Increase in notes payable, net	471			184
Proceeds —
Long-term debt issuances	12,038			3,075
Common stock issuances	1,383			116
Short-term borrowings	—			320
Redemptions and repurchases —
Long-term debt	(1,272		)	(939		)
Interest-bearing refundable deposits	—			(275		)
Preferred and preference stock	—			(412		)
Common stock repurchased	—			(115		)
Short-term borrowings	(475		)	(250		)
Distributions to noncontrolling interests	(11		)	(1		)
Capital contributions from noncontrolling interests	179			78
Purchase of membership interests from noncontrolling interests	(129		)	—
Payment of common stock dividends	(1,023		)	(972		)
Other financing activities	(108		)	(47		)
Net cash provided from financing activities	11,053			762
Net Change in Cash and Cash Equivalents	493			103
Cash and Cash Equivalents at Beginning of Period	1,404			710
Cash and Cash Equivalents at End of Period	$	1,897		$	813
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $61 and $57 capitalized for 2016 and 2015, respectively)	$	458		$	374
Income taxes, net	(138		)	(16		)
Noncash transactions — Accrued property additions at end of period	549			345

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 June 30, 2016			At December 31, 2015
	(in millions)
Current Assets:
Cash and cash equivalents	$	1,897		$	1,404
Restricted cash and cash equivalents	7,963			—
Receivables —
Customer accounts receivable	1,281			1,058
Unbilled revenues	590			397
Under recovered regulatory clause revenues	12			63
Income taxes receivable, current	—			144
Other accounts and notes receivable	247			398
Accumulated provision for uncollectible accounts	(14		)	(13		)
Fossil fuel stock, at average cost	798			868
Materials and supplies, at average cost	1,210			1,061
Vacation pay	181			178
Prepaid expenses	563			495
Other regulatory assets, current	350			402
Other current assets	71			71
Total current assets	15,149			6,526
Property, Plant, and Equipment:
In service	78,112			75,118
Less accumulated depreciation	24,778			24,253
Plant in service, net of depreciation	53,334			50,865
Other utility plant, net	174			233
Nuclear fuel, at amortized cost	934			934
Construction work in progress	9,451			9,082
Total property, plant, and equipment	63,893			61,114
Other Property and Investments:
Nuclear decommissioning trusts, at fair value	1,578			1,512
Leveraged leases	763			755
Goodwill	264			2
Other intangible assets, net of amortization of $14 and $12 at June 30, 2016 and December 31, 2015, respectively	490			317
Miscellaneous property and investments	230			166
Total other property and investments	3,325			2,752
Deferred Charges and Other Assets:
Deferred charges related to income taxes	1,580			1,560
Unamortized loss on reacquired debt	220			227
Other regulatory assets, deferred	5,460			4,989
Income taxes receivable, non-current	413			413
Other deferred charges and assets	833			737
Total deferred charges and other assets	8,506			7,926
Total Assets	$	90,873		$	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 June 30, 2016			At December 31, 2015
	(in millions)
Current Liabilities:
Securities due within one year	$	2,724		$	2,674
Notes payable	1,372			1,376
Accounts payable	1,493			1,905
Customer deposits	408			404
Accrued taxes —
Accrued income taxes	13			19
Other accrued taxes	398			484
Accrued interest	289			249
Accrued vacation pay	229			228
Accrued compensation	335			549
Asset retirement obligations, current	349			217
Liabilities from risk management activities	95			156
Other regulatory liabilities, current	115			278
Other current liabilities	694			590
Total current liabilities	8,514			9,129
Long-term Debt	35,368			24,688
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	12,563			12,322
Deferred credits related to income taxes	183			187
Accumulated deferred investment tax credits	1,427			1,219
Employee benefit obligations	2,485			2,582
Asset retirement obligations, deferred	4,129			3,542
Unrecognized tax benefits	380			370
Other cost of removal obligations	1,154			1,162
Other regulatory liabilities, deferred	335			254
Other deferred credits and liabilities	724			720
Total deferred credits and other liabilities	23,380			22,358
Total Liabilities	67,262			56,175
Redeemable Preferred Stock of Subsidiaries	118			118
Redeemable Noncontrolling Interests	47			43
Stockholders' Equity:
Common Stockholders' Equity:
Common stock, par value $5 per share —
Authorized — 1.5 billion shares
Issued — June 30, 2016: 942 million shares
— December 31, 2015: 915 million shares
Treasury — June 30, 2016: 0.8 million shares
— December 31, 2015: 3.4 million shares
Par value	4,708			4,572
Paid-in capital	7,499			6,282
Treasury, at cost	(30		)	(142		)
Retained earnings	10,085			10,010
Accumulated other comprehensive loss	(247		)	(130		)
Total Common Stockholders' Equity	22,015			20,592
Preferred and Preference Stock of Subsidiaries	609			609
Noncontrolling Interests	822			781
Total Stockholders' Equity	23,446			21,982
Total Liabilities and Stockholders' Equity	$	90,873		$	78,318

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

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

SECOND QUARTER 2016 vs. SECOND QUARTER 2015

AND

YEAR-TO-DATE 2016 vs. YEAR-TO-DATE 2015

OVERVIEW

Southern Company is a holding company that owns all of the common stock of the traditional electric 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 as of June 30, 2016 of electricity sales by the traditional electric operating companies and Southern Power. The four traditional electric 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 providing products and services in the areas of distributed generation, energy efficiency, and utility infrastructure, as well as investments in telecommunications and leveraged lease projects. 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.

Merger with Southern Company Gas

Southern Company Gas, formerly known as AGL Resources Inc., is an energy services holding company whose primary business is the distribution of natural gas through natural gas distribution utilities. On July 1, 2016, Southern Company completed the Merger for a total purchase price of approximately $8.0 billion and Southern Company Gas became a wholly-owned, direct subsidiary of Southern Company.

Prior to the completion of the Merger on July 1, 2016, Southern Company and Southern Company Gas operated as separate companies. Accordingly, except for specific references to the Merger, the discussion and analysis of results of operations and financial condition as of and for the three and six months ended June 30, 2016 set forth herein relate solely to Southern Company and do not include Southern Company Gas. Following the Merger, the results of operations and financial condition of Southern Company Gas will be consolidated with those of Southern Company. The descriptions herein of strategy and outlook and the risks and challenges Southern Company faces include Southern Company Gas, to the extent material. See Note (I) to the Condensed Financial Statements under "Southern Company – Merger with Southern Company Gas" herein for additional information regarding the Merger.

During the three and six months ended June 30, 2016, Southern Company recorded in its statements of income external transaction costs for financing, legal, and consulting services associated with the Merger of approximately $43.4 million and $63.3 million, respectively, of which $26.9 million and $32.9 million is included in operating expenses and $16.5 million and $30.4 million is included in other income and (expense), respectively.

See RISK FACTORS in Item 1A herein for additional information related to the various risks related to the Merger.

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.

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$(17)	(2.7)	$(41)	(3.6)

Consolidated net income attributable to Southern Company was $612 million ($0.65 per share) for the second quarter 2016 compared to $629 million ($0.69 per share) for the second quarter 2015. For year-to-date 2016, consolidated net income attributable to Southern Company was $1.10 billion ($1.19 per share) compared to $1.14 billion ($1.25 per share) for the corresponding period in 2015. These decreases were primarily the result of higher interest expenses, higher depreciation and amortization, and higher charges related to revisions of the estimated costs expected to be incurred on Mississippi Power's construction of the Kemper IGCC. These decreases were partially offset by increases in retail revenues resulting from retail base rate increases as well as the 2015 correction of a Georgia Power billing error and a decrease in income taxes primarily from income tax benefits at Southern Power. Also contributing to the year-to-date 2016 decrease was lower retail revenues due to milder weather compared to the corresponding period in 2015.

Retail Revenues

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$34	0.9	$(132)	(1.8)

In the second quarter 2016, retail revenues were $3.75 billioncompared to $3.71 billion for the corresponding period in 2015. For year-to-date 2016, retail revenues were $7.1 billion compared to $7.3 billion for the corresponding period in 2015.

Details of the changes in retail revenues were as follows:

	Second Quarter 2016					Year-to-Date 2016
	(in millions)			(% change)		(in millions)			(% change)
Retail – prior year	$	3,714				$	7,256
Estimated change resulting from –
Rates and pricing	186			5.0		296			4.1
Sales growth (decline)	(18		)	(0.5	)	4			0.1
Weather	(2		)	(0.1	)	(87		)	(1.2	)
Fuel and other cost recovery	(132		)	(3.5	)	(345		)	(4.8	)
Retail – current year	$	3,748		0.9	%	$	7,124		(1.8	)%

Revenues associated with changes in rates and pricing increased in the second quarter and year-to-date 2016 when compared to the corresponding periods in 2015 primarily due to increases in base tariffs at Georgia Power under the 2013 ARP and the NCCR tariff and increased revenues at Alabama Power under Rate CNP Compliance, all effective January 1, 2016. The increase in rates and pricing was also due to the 2015 correction of a Georgia Power

16

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

billing error to a small number of large commercial and industrial customers and 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 decreased in the second quarter 2016 when compared to the corresponding period in 2015. Weather-adjusted residential KWH sales and weather-adjusted commercial KWH sales decreased 0.2% and 1.9%, respectively, in the second quarter 2016 primarily due to decreased customer usage, partially offset by customer growth. Industrial KWH sales decreased 1.9% in the second quarter 2016 primarily in the chemicals, primary metals, textiles, and pipeline sectors, partially offset by increases in the paper and lumber sectors. A strong dollar, low oil prices, and weak global economic conditions have constrained growth in the industrial sector.

Revenues attributable to changes in sales increased slightly for year-to-date 2016 when compared to the corresponding period in 2015. Weather-adjusted residential KWH sales increased 0.6% for year-to-date 2016 due to customer growth, partially offset by decreased customer usage. Weather-adjusted commercial KWH sales decreased 0.6% for year-to-date 2016 primarily due to decreased customer usage, partially offset by customer growth. Industrial KWH sales decreased 1.5% for year-to-date 2016 primarily in the chemicals, primary metals, non-manufacturing, textiles, and pipeline sectors, partially offset by increases in the paper, stone, clay, and glass, and lumber sectors. A strong dollar, low oil prices, and weak global economic 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, year-to-date 2016 weather-adjusted residential sales increased 0.7%, weather-adjusted commercial sales decreased 0.4%, and industrial KWH sales decreased 1.4% as compared to the corresponding period in 2015.

Fuel and other cost recovery revenues decreased $132 million and $345 million in the second quarter and year-to-date 2016, respectively, when compared to the corresponding periods in 2015 primarily due to a decrease in fuel prices.

Electric rates for the traditional electric 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 PPA costs, and do not affect net income. The traditional electric operating companies each have one or more regulatory mechanisms to recover other costs such as environmental and other compliance costs, storm damage, new plants, and PPA capacity costs.

Wholesale Revenues

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$(2)	(0.4)	$(73)	(8.0)

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.

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 second quarter 2016, wholesale revenues were $446 million compared to $448 million for the corresponding period in 2015. This decrease was primarily related to a $21 million decrease in capacity revenues, partially offset by a $19 million increase in energy revenues. The decrease in capacity revenues was primarily due to the elimination in consolidation of a Southern Power PPA that was remarketed from a third party to Georgia Power in January 2016, the expiration of Plant Scherer Unit 3 power sales agreements at Gulf Power, and the expiration of wholesale contracts at Georgia Power. The increase in energy revenues was primarily due to an increase in short-term sales and renewable energy sales at Southern Power, partially offset by lower fuel prices.

For year-to-date 2016, wholesale revenues were $842 million compared to $915 million for the corresponding period in 2015. This decrease was primarily related to a $64 million decrease in capacity revenues and a $9 million decrease in energy revenues. The decrease in capacity revenues was primarily due to the elimination in consolidation of a Southern Power PPA that was remarketed from a third party to Georgia Power in January 2016, unit retirements as well as the expiration of wholesale contracts at Georgia Power, and the expiration of Plant Scherer Unit 3 power sales agreements at Gulf Power. The decrease in energy revenues was primarily due to lower fuel prices, partially offset by an increase in short-term sales and renewable energy sales at Southern Power.

See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Gulf Power" 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 Revenues

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$86	N/M	$113	N/M

N/M - Not meaningful

In the second quarter 2016, other revenues were $99 million compared to $13 million for the corresponding period in 2015. For year-to-date 2016, other revenues were $137 million compared to $24 million for the corresponding period in 2015. These increases were primarily due to $59 million in revenues from products and services at PowerSecure International, Inc. (PowerSecure), which was acquired on May 9, 2016. Additionally, for the second quarter and year-to-date 2016, revenues from certain unregulated sales of products and services by the traditional electric operating companies of $20 million and $46 million, respectively, were reclassified as other revenues for consistency of presentation on a consolidated basis. In prior periods, these revenues were included in other income (expense), net.

See Note (I) to the Condensed Financial Statements under "Southern Company – Acquisition of PowerSecure International, Inc." herein for additional information.

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Fuel and Purchased Power Expenses

	Second Quarter 2016 vs. Second Quarter 2015				Year-to-Date 2016 vs. Year-to-Date 2015
	(change in millions)			(% change)	(change in millions)			(% change)
Fuel	$	(177	)	(14.8)	$	(478	)	(19.8)
Purchased power	18			10.5	39			12.4
Total fuel and purchased power expenses	$	(159	)		$	(439	)

In the second quarter 2016, total fuel and purchased power expenses were $1.2 billion compared to $1.4 billion for the corresponding period in 2015. The decrease was primarily the result of a $159 million decrease in the average cost of fuel and purchased power primarily due to lower natural gas and coal prices.

For year-to-date 2016, total fuel and purchased power expenses were $2.3 billion compared to $2.7 billion for the corresponding period in 2015. The decrease was primarily the result of a $376 million decrease in the average cost of fuel and purchased power primarily due to lower natural gas and coal prices and a $63 million net decrease in the volume of KWHs generated and purchased.

Fuel and purchased power energy transactions at the traditional electric 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:

	Second Quarter 2016	Second Quarter 2015	Year-to-Date 2016	Year-to-Date 2015
Total generation (billions of KWHs)	45	46	89	92
Total purchased power (billions of KWHs)	4	4	8	6
Sources of generation (percent) —
Coal	32	39	30	36
Nuclear	16	15	17	16
Gas	48	42	47	44
Hydro	2	3	4	3
Other Renewables	2	1	2	1
Cost of fuel, generated (cents per net KWH) —
Coal	3.20	3.37	3.22	3.52
Nuclear	0.82	0.84	0.82	0.75
Gas	2.24	2.76	2.20	2.73
Average cost of fuel, generated (cents per net KWH)	2.33	2.70	2.28	2.70
Average cost of purchased power (cents per net KWH)(*)	5.03	5.63	5.14	6.26

(*) 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 second quarter 2016, fuel expense was $1.0 billion compared to $1.2 billion for the corresponding period in 2015. The decrease was primarily due to a 19.2% decrease in the volume of KWHs generated by coal, an 18.8%

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

decrease in the average cost of natural gas per KWH generated, and a 5.0% decrease in the average cost of coal per KWH generated, partially offset by a 14.7% increase in the volume of KWHs generated by natural gas.

For year-to-date 2016, fuel expense was $1.9 billion compared to $2.4 billion for the corresponding period in 2015. The decrease was primarily due to a 20.4% decrease in the volume of KWHs generated by coal, a 19.4% decrease in the average cost of natural gas per KWH generated, and an 8.5% decrease in the average cost of coal per KWH generated, partially offset by a 4.6% increase in the volume of KWHs generated by natural gas.

Purchased Power

In the second quarter 2016, purchased power expense was $189 million compared to $171 million for the corresponding period in 2015. The increase was primarily due to a 20.9% increase in the volume of KWHs purchased, partially offset by a 10.7% decrease in the average cost per KWH purchased, primarily as a result of lower natural gas and coal prices.

For year-to-date 2016, purchased power expense was $354 million compared to $315 million for the corresponding period in 2015. The increase was primarily due to a 33.0% increase in the volume of KWHs purchased, partially offset by a 17.9% 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.

Cost of Sales

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$58	N/M	$77	N/M

N/M - Not meaningful

In the second quarter and year-to-date 2016, cost of sales were $58 million and $77 million, respectively. These costs were primarily related to sales of products and services by PowerSecure, which was acquired on May 9, 2016. Additionally, for the second quarter and year-to-date 2016, costs of $13 million and $32 million, respectively, related to certain unregulated sales of products and services by the traditional electric operating companies, were reclassified as cost of sales for consistency of presentation on a consolidated basis. In prior periods, these costs were included in other income (expense), net.

See "Other Revenues" herein and Note (I) to the Condensed Financial Statements under "Southern Company – Acquisition of PowerSecure International, Inc." herein for additional information.

Other Operations and Maintenance Expenses

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$(1)	(0.1)	$(16)	(0.7)

Other operations and maintenance expenses decreased slightly in the second quarter 2016 as compared to the corresponding period in 2015. The decrease was primarily related to a $22 million decrease in employee compensation and benefits including pension costs and an $18 million decrease in scheduled outage and maintenance costs at generation facilities, partially offset by $28 million in transaction fees related to the Merger and the acquisition of PowerSecure and $10 million in operations and maintenance expenses at PowerSecure since the acquisition closed on May 9, 2016.

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Other operations and maintenance expenses decreased slightly for year-to-date 2016 as compared to the corresponding period in 2015. The decrease was primarily due to a $45 million decrease in scheduled outage and maintenance costs at generation facilities and a $36 million decrease in employee compensation and benefits including pension costs. These decreases were partially offset by $34 million in transaction fees related to the Merger and the acquisition of PowerSecure, $10 million in operations and maintenance expenses at PowerSecure since the acquisition closed on May 9, 2016, and an increase of $10 million in general business expenses associated with Southern Power's overall growth strategy.

See Note (F) to the Condensed Financial Statements herein for additional information related to pension costs and Note (I) to the Condensed Financial Statements under "Southern Company" herein for additional information related to the Merger and the acquisition of PowerSecure.

Depreciation and Amortization

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$69	13.8	$123	12.5

In the second quarter 2016, depreciation and amortization was $569 million compared to $500 million for the corresponding period in 2015. The increase was primarily due to additional plant in service at the traditional electric operating companies and Southern Power.

For year-to-date 2016, depreciation and amortization was $1.1 billion compared to $987 million for the corresponding period in 2015. The increase was primarily due to an $86 million increase related to additional plant in service at the traditional electric operating companies and Southern Power. Also contributing to the increase, Gulf Power recorded $13 million less of a reduction in depreciation compared to the corresponding period in 2015, as authorized by the Florida PSC.

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

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$58	N/M	$102	N/M

N/M - Not meaningful

In the second quarter 2016 and 2015, estimated probable losses on the Kemper IGCC of $81 million and $23 million, respectively, were recorded at Southern Company. For year-to-date 2016 and 2015, estimated probable losses on the Kemper IGCC of $134 million and $32 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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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Interest Expense, Net of Amounts Capitalized

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$113	62.8	$146	37.2

In the second quarter 2016, interest expense, net of amounts capitalized was $293 million compared to $180 million in the corresponding period in 2015. For year-to-date 2016, interest expense, net of amounts capitalized was $539 million compared to $393 million in the corresponding period in 2015. These increases were primarily due to an increase in outstanding long-term debt related to the Merger, as well as increases in average outstanding long-term debt balances and higher interest rates at the traditional electric operating companies. Also contributing to the increases was the May 2015 termination of an asset purchase agreement between Mississippi Power and SMEPA and the resulting reversal of accrued interest on related deposits.

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

Other Income (Expense), Net

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$(17)	N/M	$(38)	N/M

N/M - Not meaningful

In the second quarter 2016, other income (expense), net was $(29) million compared to $(12) million for the corresponding period in 2015. For year-to-date 2016, other income (expense), net was $(57) million compared to $(19) million for the corresponding period in 2015. These changes were primarily due to fees associated with the Bridge Agreement for the Merger. Additionally, in the second quarter 2016, revenues and costs associated with certain unregulated sales of products and services by the traditional electric operating companies were reclassified to other revenues and cost of sales for consistency of presentation on a consolidated basis following the PowerSecure acquisition. For the second quarter and year-to-date 2016, net amounts reclassified were $7 million and $14 million, respectively.

See "Other Revenues" and "Cost of Sales" herein and Note 12 to the financial statements of Southern Company under "Southern Company – Merger Financing" in Item 8 of the Form 10-K for additional information.

Income Taxes

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$(30)	(9.9)	$(82)	(14.2)

In the second quarter 2016, income taxes were $272 million compared to $302 million for the corresponding period in 2015. For year-to-date 2016, income taxes were $494 million compared to $576 million for the corresponding period in 2015. These decreases were primarily due to increased federal income tax benefits from ITCs and PTCs at Southern Power and increased tax benefits related to the estimated probable losses on Mississippi Power's construction of the Kemper IGCC, partially offset by an increase related to state income tax benefits realized in 2015.

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 and, as

22

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

a result of closing the Merger on July 1, 2016, Southern Company Gas' primary business of natural gas distribution. These factors include the traditional electric operating companies' and Southern Company Gas' 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 and natural gas businesses 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 prices of electricity and natural gas, 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 and natural gas is primarily driven by economic growth. The pace of economic growth and electricity and natural gasdemand may be affected by changes in regional and global economic conditions, which may impact future earnings.

Volatility of natural gas prices has a significant impact on Southern Company Gas' customer rates, long-term competitive position against other energy sources, and the ability of Southern Company Gas' retail operations and wholesale services businesses to capture value from locational and seasonal spreads. Additionally, changes in commodity prices subject a significant portion of Southern Company Gas' operations to earnings variability.

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.

On July 10, 2016, Southern Company and Kinder Morgan, Inc. (Kinder Morgan) entered into a definitive agreement under which Southern Company will acquire a 50% equity interest in Southern Natural Gas Company, L.L.C. (SNG), which is the owner of a 7,600-mile pipeline system connecting natural gas supply basins in Texas, Louisiana, Mississippi, Alabama, and the Gulf of Mexico to markets in Louisiana, Mississippi, Alabama, Florida, Georgia, South Carolina, and Tennessee. In addition, the agreement commits Southern Company and Kinder Morgan to cooperatively pursue specific growth opportunities to develop natural gas infrastructure through SNG. Southern Company expects to finance the purchase price of approximately $1.5 billion with a mix of equity and debt in a credit-supportive manner. Southern Company's investment in SNG will be accounted for under the equity method of accounting.

The transaction is subject to the notification and clearance and reporting requirements under the Hart-Scott-Rodino Antitrust Improvements Act of 1976. Southern Company and Kinder Morgan expect to complete the transaction in the third quarter or early in the fourth quarter 2016. The ultimate outcome of this matter cannot be determined at this time.

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 and RISK FACTORS in Item 1A herein.

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.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 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.

Coal Combustion Residuals

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Coal Combustion Residuals" of Southern Company in Item 7 of the Form 10-K for additional information regarding the EPA's regulation of CCR.

On June 13, 2016, Georgia Power announced that all of its 29 ash ponds will cease operations and stop receiving coal ash in the next three years, and all ponds will eventually be closed either by removal, consolidation, and/or recycling for the beneficial use of coal ash or through closure in place using advanced engineering methods. On July 7, 2016, the Georgia Environmental Protection Division (EPD) proposed amendments to its state solid waste regulations to incorporate the requirements of the EPA's Disposal of Coal Combustion Residuals from Electric Utilities Rule (CCR Rule) and establish additional requirements for all of Georgia Power's onsite storage units consisting of landfills and surface impoundments. The proposed Georgia EPD regulations are expected to be finalized in October 2016 and are not anticipated to have a material impact on the Southern Company system's compliance obligations under the CCR Rule. See Note (A) to the Condensed Financial Statements herein for information regarding Southern Company's asset retirement obligations (ARO) as of June 30, 2016.

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 electric 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

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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 electric 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 May 17, 2016, the Georgia PSC approved Georgia Power's request to decrease fuel rates by 15% effective June 1, 2016, which will reduce annual billings by approximately $313 million. Georgia Power is currently scheduled to file its next fuel case by February 28, 2017.

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 (ASI), four PPAs totaling 149 MWs of Georgia Power's solar contracted capacity from Southern Power began in the first quarter 2016. During the second quarter 2016, Georgia Power executed PPAs to purchase an additional 41 MWs of solar capacity under the ASI. Ownership of any associated renewable energy credits (REC) is specified in each respective PPA. The party that owns the RECs retains the right to use them.

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. The projects are expected to be in service by the second quarter 2017 and the resulting energy purchases are expected to be recovered through Mississippi Power's fuel cost recovery mechanism. Mississippi Power may retire the RECs generated on behalf of its customers or sell the RECs, separately or bundled with energy, to third parties.

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.

In accordance with the Alabama PSC order approving up to 500 MWs of renewable projects, Alabama Power has entered into agreements to purchase power from or to build renewable generation sources, including a 72-MW solar PPA approved by the Alabama PSC in June 2016. Alabama Power is marketing the associated RECs generated by this solar PPA to customers interested in supporting renewable energy development. The terms of the renewable agreements permit Alabama Power to use the energy and retire the associated RECs in service of its customers or to sell RECs, separately or bundled with energy.

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 rate natural disaster reserve. 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 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.

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Environmental Accounting Order

In April 2016, as part of its environmental compliance strategy, Alabama Power ceased using coal at Plant Greene County Units 1 and 2 (300 MWs representing Alabama Power's ownership interest) and began operating Units 1 and 2 solely on natural gas in May 2016 and July 2016, respectively.

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 acquisition of Southern Company Gas 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) each will retain their respective merger savings, net of transition costs, as defined in the settlement agreement; through December 31, 2022, such net merger savings applicable to each utility will be shared on a 60/40 basis between their respective 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 – Merger with Southern Company Gas" herein for additional information regarding the Merger.

Integrated Resource Plan

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Georgia Power – Integrated Resource Plan" of Southern Company in Item 7 of the Form 10-K for additional information regarding Georgia Power's triennial Integrated Resource Plan (2016 IRP).

On July 28, 2016, the Georgia PSC voted to approve the 2016 IRP including the decertification and retirement of Plant Mitchell Units 3, 4A, and 4B (217 MWs) and Plant Kraft Unit 1 combustion turbine (17 MWs), as well as the decertification of the Intercession City unit (143 MWs total capacity). On August 2, 2016, the Plant Mitchell and Plant Kraft units were retired. Georgia Power exercised its contractual option to sell its 33% ownership interest in the Intercession City unit to Duke Energy Florida, Inc., with an expected closing date in late August 2016.

Additionally, the Georgia PSC approved Georgia Power's environmental compliance strategy and related expenditures proposed in the 2016 IRP, including measures taken to comply with existing government-imposed environmental mandates, subject to limits on expenditures for Plant McIntosh Unit 1 and Plant Hammond Units 1 through 4.

The Georgia PSC approved reclassification of the remaining net book value of Plant Mitchell Unit 3 and costs associated with materials and supplies remaining at the unit retirement date to a regulatory asset. Recovery of the unit's net book value will continue through December 31, 2019, as provided in the 2013 ARP. Recovery of the remaining balance of the unit's net book value as of December 31, 2019 and costs associated with materials and supplies remaining at the unit retirement date will be deferred for consideration in Georgia Power's 2019 general base rate case.

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The Georgia PSC also approved the Renewable Energy Development Initiative to procure an additional 1,200 MWs of renewable resources primarily utilizing market-based prices established through a competitive bidding process with expected in-service dates between 2018 and 2021. Additionally, 200 MWs of self-build capacity for use by Georgia Power was approved, as well as consideration for no more than 200 MWs of capacity as part of a renewable commercial and industrial program.

The Georgia PSC also approved recovery of costs up to $99 million through June 30, 2019 to preserve the nuclear option at a future generation site in Stewart County, Georgia. The timing of cost recovery will be determined by the Georgia PSC in a future base rate case. The ultimate outcome of this matter cannot be determined at this time.

Gulf Power

Through 2015, long-term non-affiliate capacity sales from Gulf Power's ownership of Plant Scherer Unit 3 (205 MWs) provided the majority of Gulf Power's wholesale earnings. The revenues from wholesale contracts covering 100% of this capacity represented 82% of Gulf Power's wholesale capacity revenues in 2015. Following contract expirations at the end of 2015 and the end of May 2016, Gulf Power's remaining contracted sales from the unit will cover approximately 24% of the unit through 2019. The expiration of these contracts is not expected to have a material impact on Southern Company's earnings. Gulf Power is actively evaluating alternatives, including, 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.

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 electric 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. Southern Company Gas is engaged in various infrastructure programs that update or expand its distribution systems to improve reliability and ensure the safety of its utility infrastructure and recovers in rates its investment and a return associated with these infrastructure programs.

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 $6.68 billion, which includes approximately $5.43 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 $2.55 billion ($1.57 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through June 30, 2016. Mississippi Power's current cost estimate includes costs through October 31, 2016, which reflects a one-month extension. The initial production of syngas began on July 14, 2016 and testing has continued on gasifier 'B' and the related lignite feed and ash systems. The schedule extension provides for time to complete mechanical equipment modifications to the gasifiers' supporting systems to increase capacity to the levels necessary to complete the remaining start-up activities and achieve sustained operations on both gasifiers. The remaining schedule also reflects the time expected to complete the initial operation and testing of the facility's syngas clean-up systems, as well as the integration of all systems necessary for both combustion turbines to simultaneously generate electricity with syngas.

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.

Litigation

On April 26, 2016, a complaint against Mississippi Power was filed in Harrison County Circuit Court (Circuit Court) by Biloxi Freezing & Processing Inc., Gulfside Casino Partnership, and John Carlton Dean, which was amended and refiled on July 11, 2016 to include, among other things, Southern Company as a defendant. The individual plaintiff, John Carlton Dean, alleges that Mississippi Power and Southern Company violated the Mississippi Unfair Trade Practices Act. All plaintiffs have alleged that Mississippi Power and Southern Company concealed, falsely represented, and failed to fully disclose important facts concerning the cost and schedule of the Kemper IGCC and that these alleged breaches have unjustly enriched Mississippi Power and Southern Company. The plaintiffs seek unspecified actual damages and punitive damages; ask the Circuit Court to appoint a receiver to oversee, operate, manage, and otherwise control all affairs relating to the Kemper IGCC; ask the Circuit Court to revoke any licenses or certificates authorizing Mississippi Power or Southern Company to engage in any business related to the Kemper IGCC in Mississippi; and seek 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.

On June 9, 2016, Treetop Midstream Services, LLC (Treetop) and other related parties filed a complaint against Mississippi Power, Southern Company, and SCS in the state court in Gwinnett County, Georgia. The complaint relates to the cancelled CO₂ contract with Treetop and alleges fraudulent misrepresentation, fraudulent concealment, civil conspiracy, and breach of contract on the part of Mississippi Power, Southern Company, and SCS and seeks compensatory damages of $100 million, as well as unspecified punitive damages.

Southern Company believes these legal challenges have no merit; however, an adverse outcome in these proceedings could have an impact on Southern Company's results of operations, financial condition, and liquidity. Southern Company will vigorously defend itself in these matters, and the ultimate outcome of these matters 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

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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 information on the Kemper IGCC estimated construction costs and expected in-service date. 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.

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 $81 million ($50 million after tax) in the second quarter 2016, $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

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$540 million ($333 million after tax) in the first quarter 2013. In the aggregate, Southern Company has incurred charges of $2.55 billion ($1.57 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through June 30, 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. Further cost increases and/or extensions of the expected in-service date may result from factors including, but not limited to, difficulties integrating the systems required for sustained operations, major equipment failure, unforeseen engineering or design problems including any repairs and/or modifications to systems, and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC).

Mississippi Power's revised cost estimate includes costs through October 31, 2016. Any extension of the in-service date beyond October 31, 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 October 31, 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 $3 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 unchanged and 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. Early adoption is permitted and Southern Company intends to adopt the ASU in the fourth quarter 2016. The adoption is not expected to have a material impact on the results of operations, financial position, or cash flows of Southern Company.

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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 June 30, 2016. Through June 30, 2016, Southern Company has incurred non-recoverable cash expenditures of $2.28 billion and is expected to incur approximately $0.27 billion in additional non-recoverable cash expenditures through completion of the construction and start-up 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 $2.1 billion for the first six months of 2016 and the corresponding period in 2015. Net cash used for investing activities totaled $12.7 billion for the first six months of 2016 primarily due to an investment in restricted cash to be used to complete the Merger, as well as construction of generation, transmission, and distribution facilities and installation of equipment to comply with environmental standards. Net cash provided from financing activities totaled $11.1 billion for the first six months of 2016 primarily due to issuances of long-term debt and common stock associated with financing and completing the Merger. Cash flows 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 six months of 2016 include increases of $10.7 billion in long-term debt, $8.0 billion in restricted cash and cash equivalents, and $1.4 billion in total common stockholder's equity primarily associated with financing and completing the Merger; an increase of $2.8 billion in total property, plant, and equipment to comply with environmental standards and construction of generation, transmission, and distribution facilities; and increases of $0.7 billion in AROs and $0.5 billion in other regulatory assets, deferred primarily related to changes in ash pond closure strategy primarily for Georgia Power. See Notes (A) and (I) to the Condensed Financial Statements herein under "Asset Retirement Obligations" and "Southern Company – Merger with Southern Company Gas," respectively, for additional information.

At the end of the second quarter 2016, the market price of Southern Company's common stock was $53.63 per share (based on the closing price as reported on the New York Stock Exchange) and the book value was $23.38 per share, representing a market-to-book ratio of 229%, compared to $46.79, $22.59, and 207%, respectively, at the end of 2015. Southern Company's common stock dividend for the second quarter 2016 was $0.560 per share compared to $0.5425 per share in the second 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 $3.3 billion will be required through June 30, 2017 to fund maturities of long-term debt, which includes $0.6 billion with respect to Southern Company Gas that was assumed subsequent to June 30, 2016 in connection with the Merger. In addition, approximately $1.5 billion will be required for Southern Company's acquisition of a 50% equity interest in SNG, which is expected to be completed in the third quarter or early in the fourth quarter 2016. See "Sources of Capital" and Note (I) to the Condensed Financial Statements under "Southern Company – Natural Gas Pipeline Venture" herein for additional information.

The Southern Company system's construction program is currently estimated to total $9.4 billion for 2016, $5.2 billion for 2017, and $5.5 billion for 2018. These amounts include expenditures of approximately $0.7 billion related to the construction and start-up of the Kemper IGCC in 2016; $0.6 billion, $0.7 billion, and $0.4 billion to

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continue construction on Plant Vogtle Units 3 and 4 in 2016, 2017, and 2018, respectively; and $4.4 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. In addition, Southern Company Gas' construction program is currently estimated to total $0.8 billion for the period from July 1, 2016 to December 31, 2016.

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 and Southern Company Gas' capital requirements. See "Capital Requirements and Contractual Obligations" herein for additional information.

Except as described herein, the traditional electric operating companies, Southern Company Gas, 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. Eligible Project Costs incurred through June 30, 2016 would allow for borrowings of up to $2.6 billion under the FFB Credit Facility, of which Georgia Power has borrowed $2.5 billion. 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.

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

32

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 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 June 30, 2016, Southern Company's current assets exceeded current liabilities by $6.6 billion. Excluding restricted cash of $8.0 billion associated with the Merger, Southern Company's current liabilities exceeded current assets by $1.3 billion, primarily due to long-term debt that is due within one year of $2.7 billion, including approximately $0.9 billion at the parent company, $0.2 billion at Alabama Power, $0.7 billion at Georgia Power, $0.2 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 electric operating companies, Southern Power, and Southern Company Gas 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 electric 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 June 30, 2016, Southern Company and its subsidiaries had approximately $1.9 billion of cash and cash equivalents. In addition, Southern Company had approximately $8.0 billion of restricted cash, which was subsequently used to complete the Merger. Committed credit arrangements with banks at June 30, 2016 were as follows:

	Expires												Executable Term Loans				Due Within One Year
Company(a)	2016		2017		2018		2020		Total		Unused		One Year		Two Years		Term Out		No Term Out
	(in millions)								(in millions)				(in millions)				(in millions)
Southern Company	$	—	$	—	$	1,000	$	1,250	$	2,250	$	2,250	$	—	$	—	$	—	$	—
Alabama Power	3		32		500		800		1,335		1,335		—		—		—		35
Georgia Power	—		—		—		1,750		1,750		1,732		—		—		—		—
Gulf Power	75		40		165		—		280		280		45		—		45		70
Mississippi Power	115		60		—		—		175		150		—		15		15		160
Southern Power Company(b)	—		—		—		600		600		560		—		—		—		—
Other	25		45		—		40		110		80		20		—		20		50
Total	$	218	$	177	$	1,665	$	4,440	$	6,500	$	6,387	$	65	$	15	$	80	$	315

(a) Excludes Southern Company Gas as the Merger was not completed at June 30, 2016. Southern Company Gas has committed credit arrangements with banks totaling $2.0 billion at July 1, 2016, of which $0.1 billion expire in 2017 and $1.9 billion expire in 2018.

(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.

On May 24, 2016, the $8.1 billion Bridge Agreement to provide Merger financing, to the extent necessary, was terminated.

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

33

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 electric 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.

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 electric 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 June 30, 2016 was approximately $1.9 billion. In addition, at June 30, 2016, the traditional electric operating companies had approximately $320 million of fixed rate pollution control revenue bonds outstanding that were required to be reoffered within the next 12 months.

Southern Company, the traditional electric operating companies, and Southern Power make short-term borrowings primarily through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above. Southern Company, the traditional electric 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 June 30, 2016(a)				Short-term Debt During the Period(a,b)
	Amount Outstanding		Weighted Average Interest Rate		Average Amount Outstanding		Weighted Average Interest Rate		Maximum Amount Outstanding
	(in millions)				(in millions)				(in millions)
Commercial paper	$	478	0.8	%	$	1,082	0.8	%	$	1,712
Short-term bank debt	125		1.5	%	215		1.5	%	262
Total	$	603	1.0	%	$	1,297	0.9	%

(a) Excludes Southern Company Gas as the Merger was not completed at June 30, 2016.

(b) Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 2016.

In addition to the short-term borrowings in the table above, the Project Credit Facilities had total amounts outstanding as of June 30, 2016 of $769 million at a weighted average interest rate of 2.02%. For the three-month period ended June 30, 2016, these credit agreements had a maximum amount outstanding of $769 million and an average amount outstanding of $586 million at a weighted average interest rate of 2.03%.

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

Credit Rating Risk

At June 30, 2016, Southern Company and its subsidiaries did 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.

34

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The maximum potential collateral requirements under these contracts at June 30, 2016 were as follows:

Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB and/or Baa2	$	29
At BBB- and/or Baa3	$	597
Below BBB- and/or Baa3	$	2,519

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.

On May 12, 2016, Fitch downgraded the senior unsecured long-term debt rating of Southern Company to A- from A and revised the ratings outlook from negative to stable. Fitch also downgraded the senior unsecured long-term debt rating of Mississippi Power to BBB+ from A- and revised the ratings outlook from negative to stable.

On May 13, 2016, Moody's downgraded the senior unsecured long-term debt rating of Southern Company to Baa2 from Baa1 and revised the ratings outlook from negative to stable.

Financing Activities

On May 11, 2016, Southern Company issued 18.3 million shares of common stock in an underwritten offering for an aggregate purchase price of approximately $889 million. Of the 18.3 million shares, approximately 2.6 million were issued from treasury and the remainder were newly issued shares. The proceeds were used to fund a portion of the Merger and for other general corporate purposes.

In addition, during the first six months of 2016, Southern Company issued approximately 11.6 million shares of common stock primarily through employee equity compensation plans and received proceeds of approximately $494 million.

The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first six 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)
Southern Company	$	8,500	$	—	$	—	$	—		$	—
Alabama Power	400		200		—		45			—
Georgia Power	650		500		4		300			3
Gulf Power	—		125		—		—			—
Mississippi Power	—		—		—		1,100			651
Southern Power	1,241		—		—		2			4
Other	—		—		—		—			10
Elimination(c)	—		—		—		(200		)	(225		)
Total	$	10,791	$	825	$	4	$	1,247		$	443

(a) Excludes Southern Company Gas as the Merger was not completed at June 30, 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.

35

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

In February 2016, Southern Company entered into $700 million notional amount of forward-starting interest rate swaps to hedge exposure to interest rate changes related to anticipated debt issuances. These interest rate swaps were settled in May 2016.

In May 2016, Southern Company issued the following series of senior notes for an aggregate principal amount of $8.5 billion:

• $0.5 billion of 1.55% Senior Notes due July 1, 2018;

• $1.0 billion of 1.85% Senior Notes due July 1, 2019;

• $1.5 billion of 2.35% Senior Notes due July 1, 2021;

• $1.25 billion of 2.95% Senior Notes due July 1, 2023;

• $1.75 billion of 3.25% Senior Notes due July 1, 2026;

• $0.5 billion of 4.25% Senior Notes due July 1, 2036; and

• $2.0 billion of 4.40% Senior Notes due July 1, 2046.

The net proceeds were used to fund a portion of the Merger and related transaction costs and for other general corporate purposes.

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 with a syndicate of financial institutions 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.

In May 2016, Gulf Power entered into an 11-month floating rate bank loan bearing interest based on one-month LIBOR. This short-term loan was for $100 million aggregate principal amount and the proceeds were used to repay existing indebtedness and for working capital and other general corporate purposes.

Georgia Power's "Other Long-Term Debt Issuances" reflected in the table above include borrowings under the FFB Credit Facility in an aggregate principal amount of $300 million in June 2016. The interest rate applicable to the $300 million principal amount is 2.571% for an interest period that extends to the final maturity date of February 20, 2044. The proceeds were used to reimburse Georgia Power for Eligible Project Costs relating to the construction of Plant Vogtle Units 3 and 4.

During the six months ended June 30, 2016, Southern Power's subsidiaries borrowed an additional $632 million pursuant to the Project Credit Facilities at a weighted average interest rate of 2.00%. Subsequent to June 30, 2016, Southern Power's subsidiaries borrowed $48 million pursuant to the Project Credit Facilities at a weighted average interest rate of 1.98%.

In June 2016, Southern Power issued €600 million aggregate principal amount of Series 2016A 1.00% Senior Notes due June 20, 2022 and €500 million aggregate principal amount of Series 2016B 1.85% Senior Notes due June 20, 2026. The proceeds will be allocated to renewable energy generation projects. Southern Power's obligations under its euro-denominated fixed-rate notes were effectively converted to fixed-rate U.S. dollars at issuance through cross-currency swaps, removing foreign currency exchange risk associated with the interest and principal payments. See Note (H) to the Condensed Financial Statements under "Foreign Currency Derivatives" herein for additional information.

36

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

37

PART I

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

During the six months ended June 30, 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 second 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.

Southern Company completed the Merger on July 1, 2016, with Southern Company Gas surviving the Merger as a wholly-owned, direct subsidiary of Southern Company. Southern Company is currently in the process of integrating Southern Company Gas' operations and will be conducting control reviews pursuant to Section 404 of the Sarbanes-Oxley Act of 2002. See Note (I) to the Condensed Financial Statements under "Southern Company – Merger with Southern Company Gas" herein for additional information regarding the Merger.

38

ALABAMA POWER COMPANY

39

ALABAMA POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2016			2015			2016			2015
	(in millions)						(in millions)
Operating Revenues:
Retail revenues	$	1,316		$	1,326		$	2,510		$	2,594
Wholesale revenues, non-affiliates	67			57			130			123
Wholesale revenues, affiliates	9			20			31			35
Other revenues	52			52			105			104
Total operating revenues	1,444			1,455			2,776			2,856
Operating Expenses:
Fuel	295			343			564			653
Purchased power, non-affiliates	40			45			76			86
Purchased power, affiliates	55			49			88			103
Other operations and maintenance	355			370			747			768
Depreciation and amortization	175			160			347			318
Taxes other than income taxes	94			90			191			184
Total operating expenses	1,014			1,057			2,013			2,112
Operating Income	430			398			763			744
Other Income and (Expense):
Allowance for equity funds used during construction	6			14			16			29
Interest expense, net of amounts capitalized	(74		)	(69		)	(147		)	(134		)
Other income (expense), net	(4		)	(14		)	(11		)	(18		)
Total other income and (expense)	(72		)	(69		)	(142		)	(123		)
Earnings Before Income Taxes	358			329			621			621
Income taxes	142			122			245			235
Net Income	216			207			376			386
Dividends on Preferred and Preference Stock	5			7			9			17
Net Income After Dividends on Preferred and Preference Stock	$	211		$	200		$	367		$	369

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2016		2015		2016			2015
	(in millions)				(in millions)
Net Income	$	216	$	207	$	376		$	386
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $-, $3, $(1), and $-, respectively	—		5		(2		)	1
Reclassification adjustment for amounts included in net income, net of tax of $-, $-, $1, and $1, respectively	1		—		2			1
Total other comprehensive income (loss)	1		5		—			2
Comprehensive Income	$	217	$	212	$	376		$	388

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

40

ALABAMA POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Six Months Ended June 30,
	2016			2015
	(in millions)
Operating Activities:
Net income	$	376		$	386
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	419			387
Deferred income taxes	175			60
Allowance for equity funds used during construction	(16		)	(29		)
Other, net	(37		)	(23		)
Changes in certain current assets and liabilities —
-Receivables	64			(115		)
-Fossil fuel stock	(32		)	19
-Other current assets	(67		)	(52		)
-Accounts payable	(75		)	(212		)
-Accrued taxes	98			177
-Accrued compensation	(50		)	(66		)
-Retail fuel cost over recovery	(60		)	25
-Other current liabilities	8			40
Net cash provided from operating activities	803			597
Investing Activities:
Property additions	(645		)	(612		)
Nuclear decommissioning trust fund purchases	(200		)	(278		)
Nuclear decommissioning trust fund sales	200			278
Cost of removal, net of salvage	(51		)	(28		)
Change in construction payables	(27		)	28
Other investing activities	(18		)	(14		)
Net cash used for investing activities	(741		)	(626		)
Financing Activities:
Proceeds —
Senior notes issuances	400			975
Capital contributions from parent company	237			10
Pollution control revenue bonds	—			80
Other long-term debt issuances	45			—
Redemptions and repurchases —
Preferred and preference stock	—			(412		)
Pollution control revenue bonds	—			(134		)
Senior notes	(200		)	(250		)
Payment of common stock dividends	(382		)	(286		)
Other financing activities	(13		)	(32		)
Net cash provided from (used for) financing activities	87			(49		)
Net Change in Cash and Cash Equivalents	149			(78		)
Cash and Cash Equivalents at Beginning of Period	194			273
Cash and Cash Equivalents at End of Period	$	343		$	195
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $7 and $10 capitalized for 2016 and 2015, respectively)	$	131		$	118
Income taxes, net	(122		)	47
Noncash transactions — Accrued property additions at end of period	94			35

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

41

ALABAMA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Assets	At June 30, 2016			At December 31, 2015
	(in millions)
Current Assets:
Cash and cash equivalents	$	343		$	194
Receivables —
Customer accounts receivable	357			332
Unbilled revenues	174			119
Under recovered regulatory clause revenues	7			43
Income taxes receivable, current	—			142
Other accounts and notes receivable	35			20
Affiliated companies	32			50
Accumulated provision for uncollectible accounts	(9		)	(10		)
Fossil fuel stock, at average cost	271			239
Materials and supplies, at average cost	412			398
Vacation pay	66			66
Prepaid expenses	100			83
Other regulatory assets, current	87			115
Other current assets	10			10
Total current assets	1,885			1,801
Property, Plant, and Equipment:
In service	25,572			24,750
Less accumulated provision for depreciation	8,889			8,736
Plant in service, net of depreciation	16,683			16,014
Nuclear fuel, at amortized cost	368			363
Construction work in progress	423			801
Total property, plant, and equipment	17,474			17,178
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	69			71
Nuclear decommissioning trusts, at fair value	759			737
Miscellaneous property and investments	101			96
Total other property and investments	929			904
Deferred Charges and Other Assets:
Deferred charges related to income taxes	519			522
Deferred under recovered regulatory clause revenues	136			99
Other regulatory assets, deferred	1,100			1,114
Other deferred charges and assets	113			103
Total deferred charges and other assets	1,868			1,838
Total Assets	$	22,156		$	21,721

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

42

ALABAMA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholder's Equity	At June 30, 2016			At December 31, 2015
	(in millions)
Current Liabilities:
Securities due within one year	$	200		$	200
Accounts payable —
Affiliated	293			278
Other	294			410
Customer deposits	88			88
Accrued taxes —
Accrued income taxes	10			—
Other accrued taxes	93			38
Accrued interest	80			73
Accrued vacation pay	55			55
Accrued compensation	72			119
Liabilities from risk management activities	17			55
Other regulatory liabilities, current	81			240
Other current liabilities	41			39
Total current liabilities	1,324			1,595
Long-term Debt	6,894			6,654
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	4,413			4,241
Deferred credits related to income taxes	68			70
Accumulated deferred investment tax credits	114			118
Employee benefit obligations	360			388
Asset retirement obligations	1,502			1,448
Other cost of removal obligations	699			722
Other regulatory liabilities, deferred	106			136
Deferred over recovered regulatory clause revenues	102			—
Other deferred credits and liabilities	69			76
Total deferred credits and other liabilities	7,433			7,199
Total Liabilities	15,651			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	2,589			2,341
Retained earnings	2,445			2,461
Accumulated other comprehensive loss	(32		)	(32		)
Total common stockholder's equity	6,224			5,992
Total Liabilities and Stockholder's Equity	$	22,156		$	21,721

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

43

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

SECOND QUARTER 2016 vs. SECOND QUARTER 2015

AND

YEAR-TO-DATE 2016 vs. YEAR-TO-DATE 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

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$11	5.5	$(2)	(0.5)

Alabama Power's net income after dividends on preferred and preference stock for the second quarter 2016 was $211 million compared to $200 million for the corresponding period in 2015. The increase was primarily related to an increase in retail revenues under Rate CNP Compliance and a decrease in non-fuel operations and maintenance expenses. These increases to income were partially offset by decreases in customer usage and AFUDC and increases in interest expense and depreciation and amortization.

Alabama Power's net income after dividends on preferred and preference stock for year-to-date 2016 was $367 million compared to $369 million for the corresponding period in 2015. The decrease was primarily related to a decrease in retail revenues associated with milder weather for year-to-date 2016 compared to the corresponding period in 2015, a decrease in AFUDC, and increases in interest expense, taxes other than income taxes, and depreciation and amortization. These decreases to income were partially offset by an increase in revenue under Rate CNP Compliance, a decrease in non-fuel operations and maintenance expenses, and a decrease in dividends on preferred and preference stock.

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Retail Revenues

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$(10)	(0.8)	$(84)	(3.2)

In the second quarter 2016, retail revenues were $1.32 billion compared to $1.33 billion for the corresponding period in 2015. For year-to-date 2016, retail revenues were $2.51 billion compared to $2.59 billion for the corresponding period in 2015.

Details of the changes in retail revenues were as follows:

	Second Quarter 2016					Year-to-Date 2016
	(in millions)			(% change)		(in millions)			(% change)
Retail – prior year	$	1,326				$	2,594
Estimated change resulting from –
Rates and pricing	43			3.2		77			3.0
Sales growth (decline)	(9		)	(0.7	)	(1		)	(0.1	)
Weather	(3		)	(0.2	)	(48		)	(1.8	)
Fuel and other cost recovery	(41		)	(3.1	)	(112		)	(4.3	)
Retail – current year	$	1,316		(0.8	)%	$	2,510		(3.2	)%

Revenues associated with changes in rates and pricing increased in the second quarter and year-to-date 2016 when compared to the corresponding periods 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 changes in sales declined in the second quarter and year-to-date 2016 when compared to the corresponding periods in 2015. Industrial KWH sales decreased 5.5% and 4.5% for the second quarter and year-to-date 2016, respectively, when compared to the corresponding periods in 2015 as a result of a decrease in demand resulting from changes in production levels primarily in the chemicals, primary metals, and pipelines sectors. A strong dollar, low oil prices, and weak global economic conditions have constrained growth in the industrial sector. Weather-adjusted commercial KWH sales decreased 1.6% for the second quarter 2016 and remained relatively flat year-to-date 2016. Weather-adjusted residential KWH sales remained relatively flat for the second quarter and year-to-date 2016.

Revenues resulting from changes in weather decreased in the second quarter and year-to-date 2016 due to milder weather experienced in Alabama Power's service territory compared to the corresponding periods in 2015. For the second quarter 2016, the resulting decreases were 0.2% and 0.4% for residential and commercial sales revenue, respectively. For year-to-date 2016, the resulting decreases were 3.5% and 1.2% for residential and commercial sales revenue, respectively.

Fuel and other cost recovery revenues decreased in the second quarter and year-to-date 2016 when compared to the corresponding periods 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.

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Wholesale Revenues – Non-Affiliates

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$10	17.5	$7	5.7

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

In the second quarter 2016, wholesale revenues from sales to non-affiliates were $67 million compared to $57 million for the corresponding period in 2015. The increase was primarily due to a 40.6% increase in KWH sales as the result of a new wholesale contract effective December 2015, partially offset by a 16.7% decrease in the price of energy as a result of lower gas prices. For year-to-date 2016, wholesale revenues from sales to non-affiliates were $130 million compared to $123 million for the corresponding period in 2015. The increase was primarily due to a 21.1% increase in KWH sales as a result of a new wholesale contract effective December 2015, partially offset by a 12.6% decrease in the price of energy as a result of lower gas prices.

Wholesale Revenues – Affiliates

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$(11)	(55.0)	$(4)	(11.4)

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 second quarter 2016, wholesale revenues from sales to affiliates were $9 million compared to $20 million for the corresponding period in 2015. The decrease was primarily related to a 44.4% decrease in KWH sales and a 19.2% decrease in the price of energy due to the availability of lower cost generation in the Southern Company system in 2016.

Fuel and Purchased Power Expenses

	Second Quarter 2016 vs. Second Quarter 2015				Year-to-Date 2016 vs. Year-to-Date 2015
	(change in millions)			(% change)	(change in millions)			(% change)
Fuel	$	(48	)	(14.0)	$	(89	)	(13.6	)
Purchased power – non-affiliates	(5		)	(11.1)	(10		)	(11.6	)
Purchased power – affiliates	6			12.2	(15		)	(14.6	)
Total fuel and purchased power expenses	$	(47	)		$	(114	)

In the second quarter 2016, total fuel and purchased power expenses were $390 million compared to $437 million for the corresponding period in 2015. The decrease was primarily due to a $38 million decrease related to the average cost of purchased power and a $20 million decrease related to the average cost of fuel. These decreases were partially offset by an $11 million net increase related to the volume of KWHs generated and purchased.

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For year-to-date 2016, fuel and purchased power expenses were $728 million compared to $842 million for the corresponding period in 2015. The decrease was primarily due to a $51 million net decrease related to the volume of KWHs generated and purchased, a $39 million decrease related to the average cost of fuel, and a $24 million decrease related to 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:

	Second Quarter 2016	Second Quarter 2015	Year-to-Date 2016	Year-to-Date 2015
Total generation (billions of KWHs)	13	15	28	29
Total purchased power (billions of KWHs)	3	2	4	4
Sources of generation (percent) —
Coal	53	59	46	53
Nuclear	23	20	25	23
Gas	20	15	19	17
Hydro	4	6	10	7
Cost of fuel, generated (cents per net KWH) —
Coal	2.84	2.89	2.85	2.89
Nuclear	0.79	0.82	0.78	0.81
Gas	2.52	3.10	2.49	3.06
Average cost of fuel, generated (cents per net KWH)(a)	2.28	2.50	2.20	2.41
Average cost of purchased power (cents per net KWH)(b)	3.94	5.48	4.37	5.00

(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 second quarter 2016, fuel expense was $295 million compared to $343 million for the corresponding period in 2015. The decrease was primarily due to a 17.7% decrease in the volume of KWHs generated by coal and an 18.7% decrease in the average cost of natural gas per KWH generated, which excludes fuel associated with tolling agreements, partially offset by a 19.9% increase in the volume of KWHs generated by natural gas.

For year-to-date 2016, fuel expense was $564 million compared to $653 million for the corresponding period in 2015. The decrease was primarily due to an 18.6% decrease in the average cost of natural gas per KWH generated, which excludes fuel associated with tolling agreements, and a 16.5% decrease in the volume of KWHs generated by coal, partially offset by a 12.7% increase in the volume of KWHs generated by natural gas.

Purchased Power – Non-Affiliates

For year-to-date 2016, purchased power expense from non-affiliates was $76 million compared to $86 million for the corresponding period in 2015. The decrease was primarily related to a 4.4% decrease in the average cost of purchased power per KWH due to lower natural gas prices and a 4.4% decrease in the amount of energy purchased.

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ALABAMA POWER COMPANY

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

For year-to-date 2016, purchased power expense from affiliates was $88 million compared to $103 million for the corresponding period in 2015. The decrease was primarily related to an 18.1% decrease in the average cost of purchased power per KWH as a result of lower natural gas prices. The decrease was partially offset by a 4.7% increase in the amount of energy purchased due to the availability of lower cost generation in the Southern Company system in 2016.

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

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$(15)	(4.1)	$(21)	(2.7)

In the second quarter 2016, other operations and maintenance expenses were $355 million compared to $370 million for the corresponding period in 2015. The decrease was primarily due to decreases of $10 million in employee benefit costs including pension costs and $6 million in distribution overhead line maintenance expenses. These decreases were partially offset by an increase of $5 million in scheduled steam and other power generation outage costs.

For year-to-date 2016, other operations and maintenance expenses were $747 million compared to $768 million for the corresponding period in 2015. The decrease was primarily due to decreases of $19 million in employee benefit costs including pension costs, $10 million in scheduled steam and other power generation outage costs, and $6 million in distribution overhead line maintenance expenses. These decreases were partially offset by an $8 million increase in nuclear generation outage amortization.

See Note (F) to the Condensed Financial Statements herein for additional information related to pension costs.

Depreciation and Amortization

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$15	9.4	$29	9.1

In the second quarter 2016, depreciation and amortization was $175 million compared to $160 million for the corresponding period in 2015. For year-to-date 2016, depreciation and amortization was $347 million compared to $318 million for the corresponding period in 2015. These increases were 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.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Taxes Other Than Income Taxes

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$4	4.4	$7	3.8

For year-to-date 2016, taxes other than income taxes were $191 million compared to $184 million for the corresponding period in 2015. The increase was primarily due to increases in state and municipal utility license tax bases, increases in ad valorem taxes primarily due to an increase in assessed value of property, and an increase in payroll taxes.

Allowance for Equity Funds Used During Construction

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$(8)	(57.1)	$(13)	(44.8)

In the second quarter 2016, AFUDC equity was $6 million compared to $14 million for the corresponding period in 2015. For year-to-date 2016, AFUDC equity was $16 million compared to $29 million for the corresponding period in 2015. These decreases were primarily associated with capital projects being placed in service for environmental and steam generation in 2016.

Interest Expense, Net of Amounts Capitalized

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$5	7.2	$13	9.7

For year-to-date 2016, interest expense, net of amounts capitalized was $147 million compared to $134 million for the corresponding period in 2015. The increase was primarily due to an increase in debt issuances and a reduction in amounts capitalized, partially offset by maturities and a redemption of long-term debt. See Note 6 to the financial statements of Alabama Power under "Senior Notes" in Item 8 of the Form 10-K for additional information.

Other Income (Expense), Net

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$10	71.4	$7	38.9

In the second quarter 2016, other income (expense), net was $(4) million compared to $(14) million for the corresponding period in 2015. For year-to-date 2016, other income (expense), net was $(11) million compared to $(18) million for the corresponding period in 2015. The changes were primarily due to decreases in donations, partially offset by decreases in sales of non-utility property in 2016.

Income Taxes

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$20	16.4	$10	4.3

In the second quarter 2016, income taxes were $142 million compared to $122 million for the corresponding period in 2015. The increase was primarily due to higher pre-tax earnings in 2016 and state tax credits taken in 2015.

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ALABAMA POWER COMPANY

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For year-to-date 2016, income taxes were $245 million compared to $235 million for the corresponding period in 2015. The increase was primarily due to state tax credits taken in 2015.

Dividends on Preferred and Preference Stock

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$(2)	(28.6)	$(8)	(47.1)

For year-to-date 2016, dividends on preferred and preference stock were $9 million compared to $17 million for the corresponding period in 2015. These decreases were 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 and Preference 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 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

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ALABAMA POWER COMPANY

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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. On May 17, 2016, the Alabama Rivers Alliance and American Rivers filed an additional rehearing request and also filed a petition for review at the U.S. Court of Appeals for the District of Columbia Circuit. 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 rate natural disaster reserve. 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.

Environmental Accounting Order

In April 2016, as part of its environmental compliance strategy, Alabama Power ceased using coal at Plant Greene County Units 1 and 2 (300 MWs representing Alabama Power's ownership interest) and began operating Units 1 and 2 solely on natural gas in May 2016 and July 2016, respectively.

Renewables

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

In accordance with the Alabama PSC order approving up to 500 MWs of renewable projects, Alabama Power has entered into agreements to purchase power from or to build renewable generation sources, including a 72-MW solar PPA approved by the Alabama PSC in June 2016. Alabama Power is marketing the associated renewable energy credits (REC) generated by this solar PPA to customers interested in supporting renewable energy development. The terms of the renewable agreements permit Alabama Power to use the energy and retire the associated RECs in service of its customers or to sell RECs, separately or bundled with energy.

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

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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.

TheultimateoutcomeofsuchpendingorpotentiallitigationagainstAlabama Powercannotbepredictedatthistime;however,forcurrentproceedingsnotspecificallyreportedinNote(B)totheCondensedFinancialStatementshereinorinNote3tothefinancialstatementsofAlabama PowerinItem8ofthe 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. Early adoption is permitted and Alabama Power intends to adopt the ASU in the fourth quarter 2016. The adoption is not expected to have a material impact on the results of operations, financial position, or cash flows of Alabama Power.

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 June 30, 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

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

Net cash provided from operating activities totaled $803 million for the first six months of 2016, an increase of $206 million as compared to the first six months of 2015. The increase in net cash provided from operating activities was primarily due to the timing of vendor payments and lower income tax payments as a result of bonus depreciation. Net cash used for investing activities totaled $741 million for the first six months of 2016 primarily due to gross property additions related to environmental, distribution, transmission, and steam generation. Net cash provided from financing activities totaled $87 million for the first six 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 common stock dividend payments. Cash flows 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 six months of 2016 include increases of $296 million in property, plant, and equipment, primarily due to additions to environmental, transmission, distribution, and nuclear generation, $248 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 $172 million in accumulated deferred income taxes related to bonus depreciation. Other significant changes include decreases of $159 million in other regulatory liabilities, current, primarily due to the timing of fuel cost recovery and $142 million in income taxes receivable following the receipt of a federal income tax refund.

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 regarding Alabama Power's rate mechanisms.

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 June 30, 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.

53

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Alabama Power's current liabilities sometimes exceed current assets because of long-term debt maturities and the periodic use of short-term debt as a funding source, as well as significant seasonal fluctuations in cash needs.

At June 30, 2016, Alabama Power had approximately $343 million of cash and cash equivalents. Committed credit arrangements with banks at June 30, 2016 were as follows:

Expires												Due Within One Year
2016		2017		2018		2020		Total		Unused		Term Out		No Term Out
(in millions)								(in millions)				(in millions)
$	3	$	32	$	500	$	800	$	1,335	$	1,335	$	—	$	35

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 June 30, 2016 was approximately $890 million. In addition, at June 30, 2016, Alabama Power had $87 million of fixed rate pollution control revenue bonds outstanding that were required to be reoffered within the next 12 months.

Alabama Power also 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 electric 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	$	15	0.6	%	$	100

(*) Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 2016. No short-term debt was outstanding at June 30, 2016.

54

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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.

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 June 30, 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	$	333

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.

55

GEORGIA POWER COMPANY

56

GEORGIA POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2016			2015			2016			2015
	(in millions)						(in millions)
Operating Revenues:
Retail revenues	$	1,907		$	1,872		$	3,624		$	3,686
Wholesale revenues, non-affiliates	40			50			82			118
Wholesale revenues, affiliates	10			4			15			12
Other revenues	94			90			202			178
Total operating revenues	2,051			2,016			3,923			3,994
Operating Expenses:
Fuel	439			503			815			1,029
Purchased power, non-affiliates	92			78			175			138
Purchased power, affiliates	111			115			250			263
Other operations and maintenance	439			467			896			943
Depreciation and amortization	214			202			425			418
Taxes other than income taxes	100			97			197			195
Total operating expenses	1,395			1,462			2,758			2,986
Operating Income	656			554			1,165			1,008
Other Income and (Expense):
Interest expense, net of amounts capitalized	(99		)	(93		)	(193		)	(182		)
Other income (expense), net	8			1			26			16
Total other income and (expense)	(91		)	(92		)	(167		)	(166		)
Earnings Before Income Taxes	565			462			998			842
Income taxes	213			180			373			320
Net Income	352			282			625			522
Dividends on Preferred and Preference Stock	5			5			9			9
Net Income After Dividends on Preferred and Preference Stock	$	347		$	277		$	616		$	513

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2016		2015		2016		2015
	(in millions)				(in millions)
Net Income	$	352	$	282	$	625	$	522
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $-, $9, $-, and $-, respectively	—		14		—		—
Reclassification adjustment for amounts included in net income, net of tax of $-, $-, $1, and $1, respectively	1		1		1		1
Total other comprehensive income (loss)	1		15		1		1
Comprehensive Income	$	353	$	297	$	626	$	523

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

57

GEORGIA POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Six Months Ended June 30,
	2016			2015
	(in millions)
Operating Activities:
Net income	$	625		$	522
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	530			512
Deferred income taxes	157			(6		)
Allowance for equity funds used during construction	(24		)	(10		)
Deferred expenses	39			28
Contract amendment	—			(118		)
Settlement of asset retirement obligations	(52		)	(9		)
Other, net	6			9
Changes in certain current assets and liabilities —
-Receivables	(25		)	(21		)
-Fossil fuel stock	61			101
-Prepaid income taxes	(1		)	86
-Other current assets	11			(38		)
-Accounts payable	6			(110		)
-Accrued taxes	(137		)	(125		)
-Accrued compensation	(44		)	(61		)
-Other current liabilities	17			14
Net cash provided from operating activities	1,169			774
Investing Activities:
Property additions	(1,058		)	(853		)
Nuclear decommissioning trust fund purchases	(386		)	(655		)
Nuclear decommissioning trust fund sales	380			649
Cost of removal, net of salvage	(34		)	(46		)
Change in construction payables, net of joint owner portion	(75		)	26
Prepaid long-term service agreements	(14		)	(40		)
Other investing activities	17			28
Net cash used for investing activities	(1,170		)	(891		)
Financing Activities:
Increase in notes payable, net	39			44
Proceeds —
Capital contributions from parent company	239			23
Pollution control revenue bonds	—			170
Senior notes	650			—
FFB loan	300			600
Short-term borrowings	—			250
Redemptions and repurchases —
Pollution control revenue bonds	(4		)	(65		)
Senior notes	(500		)	(125		)
Short-term borrowings	—			(250		)
Payment of common stock dividends	(653		)	(517		)
Other financing activities	(16		)	(13		)
Net cash provided from financing activities	55			117
Net Change in Cash and Cash Equivalents	54			—
Cash and Cash Equivalents at Beginning of Period	67			24
Cash and Cash Equivalents at End of Period	$	121		$	24
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $10 and $5 capitalized for 2016 and 2015, respectively)	$	174		$	170
Income taxes, net	78			240
Noncash transactions — Accrued property additions at end of period	288			171

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

58

GEORGIA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Assets	At June 30, 2016			At December 31, 2015
	(in millions)
Current Assets:
Cash and cash equivalents	$	121		$	67
Receivables —
Customer accounts receivable	592			541
Unbilled revenues	293			188
Joint owner accounts receivable	51			227
Income taxes receivable, current	—			114
Other accounts and notes receivable	52			57
Affiliated	16			18
Accumulated provision for uncollectible accounts	(2		)	(2		)
Fossil fuel stock, at average cost	340			402
Materials and supplies, at average cost	477			449
Vacation pay	93			91
Prepaid income taxes	157			156
Other regulatory assets, current	123			123
Other current assets	55			92
Total current assets	2,368			2,523
Property, Plant, and Equipment:
In service	33,045			31,841
Less accumulated provision for depreciation	11,087			10,903
Plant in service, net of depreciation	21,958			20,938
Other utility plant, net	174			171
Nuclear fuel, at amortized cost	566			572
Construction work in progress	4,655			4,775
Total property, plant, and equipment	27,353			26,456
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	62			64
Nuclear decommissioning trusts, at fair value	819			775
Miscellaneous property and investments	42			43
Total other property and investments	923			882
Deferred Charges and Other Assets:
Deferred charges related to income taxes	677			679
Other regulatory assets, deferred	2,524			2,152
Other deferred charges and assets	170			173
Total deferred charges and other assets	3,371			3,004
Total Assets	$	34,015		$	32,865

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

59

GEORGIA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholder's Equity	At June 30, 2016			At December 31, 2015
	(in millions)
Current Liabilities:
Securities due within one year	$	658		$	712
Notes payable	197			158
Accounts payable —
Affiliated	407			411
Other	541			750
Customer deposits	268			264
Accrued taxes —
Accrued income taxes	—			12
Other accrued taxes	199			325
Accrued interest	107			99
Accrued vacation pay	64			62
Accrued compensation	88			142
Asset retirement obligations, current	323			179
Other current liabilities	299			181
Total current liabilities	3,151			3,295
Long-term Debt	10,120			9,616
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	5,788			5,627
Deferred credits related to income taxes	104			105
Accumulated deferred investment tax credits	199			204
Employee benefit obligations	901			949
Asset retirement obligations, deferred	2,249			1,737
Other deferred credits and liabilities	302			347
Total deferred credits and other liabilities	9,543			8,969
Total Liabilities	22,814			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	6,527			6,275
Retained earnings	4,024			4,061
Accumulated other comprehensive loss	(14		)	(15		)
Total common stockholder's equity	10,935			10,719
Total Liabilities and Stockholder's Equity	$	34,015		$	32,865

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

60

GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

SECOND QUARTER 2016 vs. SECOND QUARTER 2015

AND

YEAR-TO-DATE 2016 vs. YEAR-TO-DATE 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 acquisition of Southern Company Gas 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

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$70	25.3	$103	20.1

Georgia Power's net income after dividends on preferred and preference stock was $347 million for the second quarter 2016 compared to $277 million for the corresponding period in 2015. For year-to-date 2016, net income after dividends on preferred and preference stock was $616 million compared to $513 million for the corresponding period in 2015. The increases were primarily due to an increase in retail base revenues effective January 1, 2016, as authorized by the Georgia PSC, the 2015 correction of an error affecting billings to a small number of large commercial and industrial customers, and lower non-fuel operating expenses. The increases were partially offset by decreases in retail base revenues due to milder weather for year-to-date 2016 compared to the corresponding period in 2015.

61

GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Retail Revenues

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$35	1.9	$(62)	(1.7)

In the second quarter 2016, retail revenues were $1.91 billion compared to $1.87 billion for the corresponding period in 2015. For year-to-date 2016, retail revenues were $3.62 billion compared to $3.69 billion for the corresponding period in 2015.

Details of the changes in retail revenues were as follows:

	Second Quarter 2016					Year-to-Date 2016
	(in millions)			(% change)		(in millions)			(% change)
Retail – prior year	$	1,872				$	3,686
Estimated change resulting from –
Rates and pricing	101			5.4		146			3.9
Sales growth (decline)	(6		)	(0.3	)	2			0.1
Weather	2			0.1		(31		)	(0.8	)
Fuel cost recovery	(62		)	(3.3	)	(179		)	(4.9	)
Retail – current year	$	1,907		1.9	%	$	3,624		(1.7	)%

Revenues associated with changes in rates and pricing increased in the second quarter and year-to-date 2016 when compared to the corresponding periods in 2015 primarily due to increases in base tariffs approved under the 2013 ARP and the NCCR tariff, all effective January 1, 2016, as well as the 2015 correction of an error affecting billings since 2013 to a small number of large commercial and industrial customers under a rate plan allowing for variable demand-driven pricing. 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 decreased in the second quarter 2016 and increased slightly year-to-date 2016 when compared to the corresponding periods in 2015. Weather-adjusted residential KWH sales increased 0.6%, weather-adjusted commercial KWH sales decreased 1.7%, and weather-adjusted industrial KWH sales increased 0.6% in the second quarter 2016 when compared to the corresponding period in 2015. For year-to-date 2016, weather-adjusted residential KWH sales increased 0.5%, weather-adjusted commercial KWH sales decreased 0.5%, and weather-adjusted industrial KWH sales increased 1.0% when compared to the corresponding period in 2015. An increase of approximately 26,000 residential customers since June 30, 2015 contributed to the increase in weather-adjusted residential KWH sales. A decline in average customer usage contributed to the decrease in weather-adjusted commercial KWH sales, partially offset by an increase of approximately 3,000 commercial customers since June 30, 2015. 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 $62 million and $179 million in the second quarter and year-to-date 2016, respectively, when compared to the corresponding periods in 2015 primarily due to lower coal and natural gas prices and lower energy sales. Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these fuel cost recovery provisions, fuel revenues generally equal fuel expenses and do not affect net income. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Fuel Cost Recovery" herein for additional information.

62

GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Wholesale Revenues – Non-Affiliates

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$(10)	(20.0)	$(36)	(30.5)

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 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 second quarter 2016, wholesale revenues from sales to non-affiliates were $40 million compared to $50 million for the corresponding period in 2015 related to an $8 million decrease in capacity revenues and a $2 million decrease in energy revenues. For year-to-date 2016, wholesale revenues from sales to non-affiliates were $82 million compared to $118 million for the corresponding period in 2015 related to a $21 million decrease in capacity revenues and a $15 million decrease in energy revenues. The decreases in capacity revenues reflect the expiration of wholesale contracts in the second quarter 2016. In addition, the decrease in capacity revenues for year-to-date 2016 reflects the retirement of 14 coal-fired generating units after March 31, 2015 as a result of Georgia Power's environmental compliance strategy. The decreases in energy revenues were primarily due to lower fuel prices. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Air Quality" and "Regulatory Matters – Integrated Resource Plan" of Georgia Power in Item 7 of the Form 10-K for additional information related to Georgia Power's environmental compliance strategy.

Other Revenues

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$4	4.4	$24	13.5

In the second quarter 2016, other revenues were $94 million compared to $90 million for the corresponding period in 2015. The increase was primarily due to a $3 million increase in outdoor lighting revenues. For year-to-date 2016, other revenues were $202 million compared to $178 million for the corresponding period in 2015. The increase was primarily due to a $14 million increase related to customer temporary facilities services revenues and a $6 million increase in outdoor lighting revenues.

Fuel and Purchased Power Expenses

	Second Quarter 2016 vs. Second Quarter 2015					Year-to-Date 2016 vs. Year-to-Date 2015
	(change in millions)			(% change)		(change in millions)			(% change)
Fuel	$	(64	)	(12.7	)	$	(214	)	(20.8	)
Purchased power – non-affiliates	14			17.9		37			26.8
Purchased power – affiliates	(4		)	(3.5	)	(13		)	(4.9	)
Total fuel and purchased power expenses	$	(54	)			$	(190	)

63

GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

In the second quarter 2016, total fuel and purchased power expenses were $642 million compared to $696 million in the corresponding period in 2015. The decrease in the second quarter 2016 was due to a decrease of $63 million in the average cost of fuel and purchased power related to lower coal and natural gas prices, partially offset by a $9 million net increase related to the volume of KWHs generated and purchased to meet customer demand.

For year-to-date 2016, total fuel and purchased power expenses were $1.24 billion compared to $1.43 billion in the corresponding period in 2015. The decrease in year-to-date 2016 was primarily due to a decrease of $152 million in the average cost of fuel and purchased power related to lower coal and natural gas prices and a $38 million net decrease related to the volume of KWHs generated and purchased, primarily as a result of 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 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:

	Second Quarter 2016	Second Quarter 2015	Year-to-Date 2016	Year-to-Date 2015
Total generation (billions of KWHs)	17	17	33	34
Total purchased power (billions of KWHs)	6	6	12	11
Sources of generation (percent) —
Coal	36	40	33	37
Nuclear	24	24	24	23
Gas	38	34	40	38
Hydro	2	2	3	2
Cost of fuel, generated (cents per net KWH) —
Coal	3.37	3.75	3.45	4.18
Nuclear	0.84	0.85	0.85	0.71
Gas	2.18	2.67	2.10	2.65
Average cost of fuel, generated (cents per net KWH)	2.29	2.66	2.26	2.76
Average cost of purchased power (cents per net KWH)(*)	4.45	4.56	4.38	4.47

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

Fuel

In the second quarter 2016, fuel expense was $439 million compared to $503 million in the corresponding period in 2015. The decrease was primarily due to a 13.9% decrease in the average cost of fuel per KWH generated primarily resulting from lower coal and natural gas prices and a 10.4% decrease in the volume of KWHs generated by coal, partially offset by a 9.7% increase in the volume of KWHs generated by natural gas.

For year-to-date 2016, fuel expense was $815 million compared to $1.03 billion in the corresponding period in 2015. The decrease was primarily due to an 18.1% decrease in the average cost of fuel per KWH generated primarily resulting from lower coal and natural gas prices and a 12.7% decrease in the volume of KWHs generated by coal.

64

GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Purchased Power – Non-Affiliates

In the second quarter 2016, purchased power expense from non-affiliates was $92 million compared to $78 million in the corresponding period in 2015. The increase was primarily due to a 19.7% increase in the volume of KWHs purchased, partially offset by a 4.7% decrease in the average cost per KWH purchased primarily resulting from lower natural gas prices.

For year-to-date 2016, purchased power expense from non-affiliates was $175 million compared to $138 million in the corresponding period in 2015. The increase was primarily due to a 38.5% increase in the volume of KWHs purchased, partially offset by a 13.9% 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 second quarter 2016, purchased power expense from affiliates was $111 million compared to $115 million in the corresponding period in 2015. The decrease was the result of a 3.0% decrease in the average cost per KWH purchased, partially offset by a 5.2% increase in the volume of KWHs purchased as Georgia Power's units generally dispatched at a higher cost than other Southern Company system resources. For year-to-date 2016, purchased power expense from affiliates was $250 million compared to $263 million in the corresponding period in 2015. The decrease was the result of a 1.6% decrease in the average cost per KWH purchased and a 2.8% decrease in the volume of KWHs purchased.

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

Other Operations and Maintenance Expenses

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$(28)	(6.0)	$(47)	(5.0)

In the second quarter 2016, other operations and maintenance expenses were $439 million compared to $467 million in the corresponding period in 2015. The decrease was primarily due to decreases of $25 million in scheduled generation outage and maintenance costs and $11 million in employee benefits including pension costs, partially offset by an increase of $10 million in transmission expenses.

For year-to-date 2016, other operations and maintenance expenses were $896 million compared to $943 million in the corresponding period in 2015. The decrease was primarily due to decreases of $42 million in generation scheduled outage and maintenance costs and $18 million in employee benefits including pension costs, partially offset by an increase of $14 million in transmission expenses.

See Note (F) to the Condensed Financial Statements herein for additional information related to pension costs.

Depreciation and Amortization

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$12	5.9	$7	1.7

In the second quarter 2016, depreciation and amortization was $214 million compared to $202 million in the corresponding period in 2015. The increase was primarily due to a $9 million increase to additional plant in service

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and a $9 million increase in other cost of removal, partially offset by a decrease of $5 million related to amortization of nuclear construction financing costs that was completed in December 2015.

For year-to-date 2016, depreciation and amortization was $425 million compared to $418 million in the corresponding period in 2015. The increase was primarily due to a $16 million increase to additional plant in service and a $9 million increase in other cost of removal, partially offset by a decrease of $9 million related to amortization of nuclear construction financing costs that was completed in December 2015 and a decrease of $9 million related to unit retirements.

Interest Expense, Net of Amounts Capitalized

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$6	6.5	$11	6.0

In the second quarter 2016, interest expense, net of amounts capitalized was $99 million compared to $93 million in the corresponding period in 2015. The increase was primarily due to a $10 million increase in interest due to additional long-term borrowings from the FFB and higher interest rates on obligations for pollution control revenue bonds remarketed in 2015, partially offset by an increase of $5 million in AFUDC debt.

For year-to-date 2016, interest expense, net of amounts capitalized was $193 million compared to $182 million in the corresponding period in 2015. The increase was primarily due to a $16 million increase in interest due to additional long-term borrowings from the FFB, partially offset by an increase of $5 million in AFUDC debt.

Income Taxes

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$33	18.3	$53	16.6

In the second quarter 2016, income taxes were $213 million compared to $180 million in the corresponding period in 2015. For year-to-date 2016, income taxes were $373 million compared to $320 million in the corresponding period in 2015. The increases were 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.

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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.

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.

Coal Combustion Residuals

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Statutes and Regulations – Coal Combustion Residuals" of Georgia Power in Item 7 of the Form 10-K for additional information regarding the EPA's regulation of CCR.

On June 13, 2016, Georgia Power announced that all of its 29 ash ponds will cease operations and stop receiving coal ash in the next three years, and all ponds will eventually be closed either by removal, consolidation, and/or recycling for the beneficial use of coal ash or through closure in place using advanced engineering methods. On July 7, 2016, the Georgia Environmental Protection Division (EPD) proposed amendments to its state solid waste regulations to incorporate the requirements of the EPA's Disposal of Coal Combustion Residuals from Electric Utilities Rule (CCR Rule) and establish additional requirements for all of Georgia Power's onsite storage units consisting of landfills and surface impoundments. The proposed Georgia EPD regulations are expected to be finalized in October 2016 and are not anticipated to have a material impact on Georgia Power's compliance obligations under the CCR Rule. See Note (A) to the Condensed Financial Statements herein for information regarding Georgia Power's asset retirement obligations (ARO) as of June 30, 2016.

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

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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 acquisition of Southern Company Gas 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) each will retain their respective merger savings, net of transition costs, as defined in the settlement agreement; through December 31, 2022, such net merger savings applicable to each utility will be shared on a 60/40 basis between their respective 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 (ASI), four PPAs totaling 149 MWs of solar contracted capacity from Southern Power began in the first quarter 2016. During the second quarter 2016, Georgia Power executed PPAs to purchase an additional 41 MWs of solar capacity under the ASI. Ownership of any associated renewable energy credits (REC) is specified in each respective PPA. The party that owns the RECs retains the right to use them.

Integrated Resource Plan

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Integrated Resource Plan" of Georgia Power in Item 7 of the Form 10-K for additional information regarding Georgia Power's triennial Integrated Resource Plan (2016 IRP).

On July 28, 2016, the Georgia PSC voted to approve the 2016 IRP including the decertification and retirement of Plant Mitchell Units 3, 4A, and 4B (217 MWs) and Plant Kraft Unit 1 combustion turbine (17 MWs), as well as the decertification of the Intercession City unit (143 MWs total capacity). On August 2, 2016, the Plant Mitchell and Plant Kraft units were retired. Georgia Power exercised its contractual option to sell its 33% ownership interest in the Intercession City unit to Duke Energy Florida, Inc., with an expected closing date in late August 2016.

Additionally, the Georgia PSC approved Georgia Power's environmental compliance strategy and related expenditures proposed in the 2016 IRP, including measures taken to comply with existing government-imposed environmental mandates, subject to limits on expenditures for Plant McIntosh Unit 1 and Plant Hammond Units 1 through 4.

The Georgia PSC approved reclassification of the remaining net book value of Plant Mitchell Unit 3 and costs associated with materials and supplies remaining at the unit retirement date to a regulatory asset. Recovery of the unit's net book value will continue through December 31, 2019, as provided in the 2013 ARP. Recovery of the remaining balance of the unit's net book value as of December 31, 2019 and costs associated with materials and supplies remaining at the unit retirement date will be deferred for consideration in Georgia Power's 2019 general base rate case.

The Georgia PSC also approved the Renewable Energy Development Initiative to procure an additional 1,200 MWs of renewable resources primarily utilizing market-based prices established through a competitive bidding process with expected in-service dates between 2018 and 2021. Additionally, 200 MWs of self-build capacity for use by Georgia Power was approved, as well as consideration for no more than 200 MWs of capacity as part of a renewable commercial and industrial program.

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The Georgia PSC also approved recovery of costs up to $99 million through June 30, 2019 to preserve the nuclear option at a future generation site in Stewart County, Georgia. The timing of cost recovery will be determined by the Georgia PSC in a future base rate case. The ultimate outcome of this matter cannot be determined at this time.

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 May 17, 2016, the Georgia PSC approved Georgia Power's request to decrease fuel rates by 15% effective June 1, 2016, which will reduce annual billings by approximately $313 million. Georgia Power is currently scheduled to file its next fuel case by February 28, 2017.

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 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.

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In 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4. Georgia Power is required to file semi-annual VCM reports with the Georgia PSC by February 28 and August 31 each year. If the projected construction capital costs to be borne by Georgia Power increase by 5% above the certified cost or the projected in-service dates are significantly extended, Georgia Power is required to seek an amendment to the Plant Vogtle Units 3 and 4 certificate from the Georgia PSC. In February 2013, Georgia Power requested an amendment to the certificate to increase the estimated in-service capital cost of Plant Vogtle Units 3 and 4 from $4.4 billion to $4.8 billion and to extend the estimated in-service dates to the fourth quarter 2017 (from April 2016) and the fourth quarter 2018 (from April 2017) for Plant Vogtle Units 3 and 4, respectively. In October 2013, the Georgia PSC approved a stipulation (2013 Stipulation) between Georgia Power and the Georgia PSC Staff (Staff) to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate until the completion of Plant Vogtle Unit 3 or earlier if deemed appropriate by the Georgia PSC and Georgia Power.

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

On December 31, 2015, Westinghouse and the Vogtle Owners entered into a definitive settlement agreement (Contractor Settlement Agreement) to resolve disputes between the Vogtle Owners and the Contractor under the Vogtle 3 and 4 Agreement, including litigation that was pending in the U.S. District Court for the Southern District of Georgia (Vogtle Construction Litigation). Effective December 31, 2015, Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the Contractor entered into an amendment to the Vogtle 3 and 4 Agreement to implement the Contractor Settlement Agreement. The Contractor Settlement Agreement and the related amendment to the Vogtle 3 and 4 Agreement (i) restrict the Contractor's ability to seek further increases in the contract price by clarifying and limiting the circumstances that constitute nuclear regulatory changes in law; (ii) provide for enhanced dispute resolution procedures; (iii) revise the guaranteed substantial completion dates to match the current estimated in-service dates of June 30, 2019 for Unit 3 and June 30, 2020 for Unit 4; (iv) provide that delay liquidated damages will commence from the current estimated nuclear fuel loading date for each unit, which is December 31, 2018 for Unit 3 and December 31, 2019 for Unit 4; and (v) provide that Georgia Power, based on its ownership interest, will pay to the Contractor and capitalize to the project cost approximately $350 million, of which approximately $250 million had been paid as of June 30, 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.

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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 is conducting 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 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 incurred approximately $141 million in total construction capital costs during the period of January 1, 2016 through June 30, 2016. Georgia Power's CWIP balance for Plant Vogtle Units 3 and 4 was $3.7 billion as of June 30, 2016. The 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, of which $1.1 billion had been incurred through June 30, 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 matters, including the timely resolution of Inspections, Tests, Analyses, and Acceptance Criteria and the related approvals by the NRC, 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 labor productivity, fabrication, assembly, delivery, and installation of plant equipment, 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.

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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.

TheultimateoutcomeofsuchpendingorpotentiallitigationagainstGeorgia Powercannotbepredictedatthistime;however,forcurrentproceedingsnotspecificallyreportedinNote(B)totheCondensedFinancialStatementshereinorinNote3tothefinancialstatementsofGeorgia PowerinItem8ofthe 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.

Georgia Power regularly evaluates its operations and costs. Primarily in response to changing customer expectations and payment patterns, including electronic payments and alternative payment locations, and on-going efforts to increase overall operating efficiencies, Georgia Power initiated cost containment activities throughout the enterprise in July 2016, including the announced closure of 104 local offices and an employee attrition plan affecting approximately 300 positions. Georgia Power expects to record charges of approximately $30 million during the remainder of 2016. Such charges are not expected to have a material impact on Georgia Power's results of operations, financial position, or cash flows. The cost containment activities are expected to reduce operating costs in 2017.

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

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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. Early adoption is permitted and Georgia Power intends to adopt the ASU in the fourth quarter 2016. The adoption is not expected to have a material impact on the results of operations, financial position, or cash flows of Georgia Power.

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 June 30, 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 $1.17 billion for the first six months of 2016 compared to $774 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 $1.17 billion for the first six months of 2016 compared to $891 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 $55 million for the first six months of 2016 compared to $117 million in the corresponding period in 2015. The decrease in cash provided from financing activities is primarily due to maturities of long-term debt, higher common stock dividends, and lower borrowings from the FFB for construction of Plant Vogtle Units 3 and 4, partially offset by senior note issuances and higher capital contributions received from Southern Company. Cash flows 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 six months of 2016 include an increase in property, plant, and equipment of $897 million to comply with environmental standards and construction of generation, transmission, and distribution facilities and increases in current and deferred ARO liabilities of $656 million and other regulatory assets, deferred of $372 million primarily related to changes in ash pond closure strategy. See FUTURE EARNINGS POTENTIAL – "Environmental Matters – Coal Combustion Residuals" herein for additional information regarding changes in ash pond closure strategy.

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 $658 million will be required through June 30, 2017 to fund maturities of long-term debt. See "Sources of Capital" herein for additional information.

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GEORGIA POWER COMPANY

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 June 30, 2016 would allow for borrowings of up to $2.6 billion under the FFB Credit Facility, of which Georgia Power has borrowed $2.5 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 June 30, 2016, Georgia Power's current liabilities exceeded current assets by $783 million primarily due to scheduled maturities of long-term debt. 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 June 30, 2016, Georgia Power had approximately $121 million of cash and cash equivalents. Georgia Power's committed credit arrangement with banks at June 30, 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.

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GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 June 30, 2016 was approximately $868 million. In addition, at June 30, 2016, Georgia Power had $212 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 electric operating companies. Proceeds from such issuances for the benefit of Georgia Power are loaned directly to Georgia Power. The obligations of each company under these arrangements are several and there is no cross-affiliate credit support.

Details of short-term borrowings were as follows:

	Short-term Debt at June 30, 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	$	197	0.8	%	$	164	0.8	%	$	443

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

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 June 30, 2016 were as follows:

Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB- and/or Baa3	$	87
Below BBB- and/or Baa3	$	1,288

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

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GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 April 2016, Georgia Power's $250 million aggregate principal amount of Series 2011B 3.00% Senior Notes matured.

In June 2016, Georgia Power made additional borrowings under the FFB Credit Facility in an aggregate principal amount of $300 million. The interest rate applicable to the $300 million principal amount is 2.571% for an interest period that extends to the final maturity date of February 20, 2044. The proceeds were used to reimburse Georgia Power for Eligible Project Costs relating to the construction of Plant Vogtle Units 3 and 4.

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

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GULF POWER COMPANY

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GULF POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2016			2015			2016			2015
	(in millions)						(in millions)
Operating Revenues:
Retail revenues	$	319		$	327		$	602		$	620
Wholesale revenues, non-affiliates	15			27			31			52
Wholesale revenues, affiliates	15			13			36			35
Other revenues	16			17			31			34
Total operating revenues	365			384			700			741
Operating Expenses:
Fuel	107			122			201			232
Purchased power, non-affiliates	32			25			62			50
Purchased power, affiliates	4			9			5			17
Other operations and maintenance	77			91			155			185
Depreciation and amortization	42			40			80			60
Taxes other than income taxes	29			28			58			56
Total operating expenses	291			315			561			600
Operating Income	74			69			139			141
Other Income and (Expense):
Allowance for equity funds used during construction	—			3			—			8
Interest expense, net of amounts capitalized	(12		)	(12		)	(25		)	(26		)
Other income (expense), net	(1		)	(1		)	(2		)	(2		)
Total other income and (expense)	(13		)	(10		)	(27		)	(20		)
Earnings Before Income Taxes	61			59			112			121
Income taxes	24			21			44			44
Net Income	37			38			68			77
Dividends on Preference Stock	3			3			5			5
Net Income After Dividends on Preference Stock	$	34		$	35		$	63		$	72

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended June 30,					For the Six Months Ended June 30,
	2016			2015		2016			2015
	(in millions)					(in millions)
Net Income	$	37		$	38	$	68		$	77
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(1), $-, $(3), and $-, respectively	(1		)	—		(4		)	—
Total other comprehensive income (loss)	(1		)	—		(4		)	—
Comprehensive Income	$	36		$	38	$	64		$	77

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 Six Months Ended June 30,
	2016			2015
	(in millions)
Operating Activities:
Net income	$	68		$	77
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	83			64
Deferred income taxes	16			40
Other, net	(3		)	3
Changes in certain current assets and liabilities —
-Receivables	(6		)	(15		)
-Fossil fuel stock	34			6
-Prepaid income taxes	2			12
-Other current assets	(1		)	1
-Accounts payable	(7		)	(9		)
-Accrued taxes	17			15
-Accrued compensation	(12		)	(10		)
-Other current liabilities	4			(1		)
Net cash provided from operating activities	195			183
Investing Activities:
Property additions	(68		)	(148		)
Cost of removal, net of salvage	(4		)	(7		)
Change in construction payables	(7		)	(15		)
Other investing activities	(5		)	(4		)
Net cash used for investing activities	(84		)	(174		)
Financing Activities:
Increase in notes payable, net	46			4
Proceeds —
Common stock issued to parent	—			20
Short-term borrowings	—			40
Redemptions and repurchases — Senior notes	(125		)	—
Payment of common stock dividends	(60		)	(65		)
Other financing activities	—			(3		)
Net cash used for financing activities	(139		)	(4		)
Net Change in Cash and Cash Equivalents	(28		)	5
Cash and Cash Equivalents at Beginning of Period	74			39
Cash and Cash Equivalents at End of Period	$	46		$	44
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $- and $3 capitalized for 2016 and 2015, respectively)	$	28		$	26
Income taxes, net	(3		)	(9		)
Noncash transactions — Accrued property additions at end of period	13			28

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 June 30, 2016			At December 31, 2015
	(in millions)
Current Assets:
Cash and cash equivalents	$	46		$	74
Receivables —
Customer accounts receivable	81			76
Unbilled revenues	77			54
Under recovered regulatory clause revenues	5			20
Income taxes receivable, current	—			27
Other accounts and notes receivable	3			9
Affiliated companies	10			1
Accumulated provision for uncollectible accounts	(1		)	(1		)
Fossil fuel stock, at average cost	74			108
Materials and supplies, at average cost	56			56
Other regulatory assets, current	65			90
Other current assets	17			22
Total current assets	433			536
Property, Plant, and Equipment:
In service	5,032			5,045
Less accumulated provision for depreciation	1,351			1,296
Plant in service, net of depreciation	3,681			3,749
Other utility plant, net	—			62
Construction work in progress	68			48
Total property, plant, and equipment	3,749			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	523			427
Other deferred charges and assets	49			33
Total deferred charges and other assets	632			521
Total Assets	$	4,818		$	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 June 30, 2016			At December 31, 2015
	(in millions)
Current Liabilities:
Securities due within one year	$	195		$	110
Notes payable	187			142
Accounts payable —
Affiliated	46			55
Other	44			44
Customer deposits	36			36
Accrued taxes —
Accrued income taxes	5			4
Other accrued taxes	25			9
Accrued interest	8			9
Accrued compensation	13			25
Deferred capacity expense, current	22			22
Other regulatory liabilities, current	19			22
Liabilities from risk management activities	32			49
Other current liabilities	30			40
Total current liabilities	662			567
Long-term Debt	987			1,193
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	905			893
Employee benefit obligations	126			129
Deferred capacity expense	130			141
Asset retirement obligations	128			113
Other cost of removal obligations	237			233
Other regulatory liabilities, deferred	46			47
Other deferred credits and liabilities	90			102
Total deferred credits and other liabilities	1,662			1,658
Total Liabilities	3,311			3,418
Preference Stock	147			147
Common Stockholder's Equity:
Common stock, without par value —
Authorized — 20,000,000 shares
Outstanding — June 30, 2016: 5,642,717 shares
— December 31, 2015: 5,642,717 shares	503			503
Paid-in capital	573			567
Retained earnings	288			285
Accumulated other comprehensive loss	(4		)	—
Total common stockholder's equity	1,360			1,355
Total Liabilities and Stockholder's Equity	$	4,818		$	4,920

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

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

SECOND QUARTER 2016 vs. SECOND QUARTER 2015

AND

YEAR-TO-DATE 2016 vs. YEAR-TO-DATE 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, long-term non-affiliate capacity sales from Gulf Power's ownership of Plant Scherer Unit 3 (205 MWs) provided the majority of Gulf Power's wholesale earnings. The revenues from wholesale contracts covering 100% of this capacity represented 82% of wholesale capacity revenues in 2015. Following contract expirations at the end of 2015 and the end of May 2016, Gulf Power's remaining contracted sales from the unit will cover approximately 24% of the unit through 2019. The expiration of these 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. Gulf Power is actively evaluating alternatives, including, 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 a settlement agreement (Rate Case Settlement Agreement) related to Gulf Power's retail base rate case. Under the terms of the Rate Case Settlement Agreement, Gulf Power is authorized to reduce depreciation and record a regulatory asset as an offset to the other cost of removal regulatory liability in an aggregate amount up to $62.5 million from January 2014 through June 2017, of which $34.9 million had been recorded as of June 30, 2016, and to accrue a return similar to AFUDC on certain transmission system upgrades placed into service after January 2014 until January 1, 2017. 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

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$(1)	(2.9)	$(9)	(12.5)

Gulf Power's net income after dividends on preference stock for the second quarter 2016 was $34 million compared to $35 million for the corresponding period in 2015. The decrease was primarily due to lower non-affiliated wholesale capacity revenues, partially offset by lower operations and maintenance expenses.

Gulf Power's net income after dividends on preference stock for year-to-date 2016 was $63 million compared to $72 million for the corresponding period in 2015. The decrease was primarily due to lower non-affiliated wholesale capacity revenues and an increase in depreciation, partially offset by lower operations and maintenance expenses.

Retail Revenues

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$(8)	(2.4)	$(18)	(2.9)

In the second quarter 2016, retail revenues were $319 million compared to $327 million for the corresponding period in 2015. For year-to-date 2016, retail revenues were $602 million compared to $620 million for the corresponding period in 2015.

Details of the changes in retail revenues were as follows:

	Second Quarter 2016					Year-to-Date 2016
	(in millions)			(% change)		(in millions)			(% change)
Retail – prior year	$	327				$	620
Estimated change resulting from –
Rates and pricing	9			2.8		17			2.7
Sales growth (decline)	(1		)	(0.3	)	1			0.2
Weather	(2		)	(0.6	)	(7		)	(1.1	)
Fuel and other cost recovery	(14		)	(4.3	)	(29		)	(4.7	)
Retail – current year	$	319		(2.4	)%	$	602		(2.9	)%

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 second quarter and year-to-date 2016 when compared to the corresponding periods 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 decreased slightly in the second quarter 2016 when compared to the corresponding period in 2015. For the second quarter 2016, weather-adjusted KWH sales to residential and commercial customers decreased 1.3% and 2.6%, respectively, due to lower customer usage, partially offset by

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GULF POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

customer growth. KWH sales to industrial customers increased 1.2% for the second quarter 2016 primarily due to decreased customer co-generation, partially offset by changes in customers' operations.

Revenues attributable to changes in sales increased slightly year-to-date 2016 when compared to the corresponding period in 2015. Weather-adjusted KWH sales to residential customers increased 0.6% due to customer growth, partially offset by lower customer usage. Weather-adjusted KWH sales to commercial customers decreased 1.4% due to lower customer usage, partially offset by customer growth. KWH sales to industrial customers increased 3.9% primarily due to decreased customer co-generation, partially offset by changes in customers' operations.

Fuel and other cost recovery revenues decreased in the second quarter and year-to-date 2016 when compared to the corresponding periods in 2015, primarily due to a decrease in fuel costs as a 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

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$(12)	(44.4)	$(21)	(40.4)

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 second quarter 2016, wholesale revenues from sales to non-affiliates were $15 million compared to $27 million for the corresponding period in 2015. For year-to-date 2016, wholesale revenues from sales to non-affiliates were $31 million compared to $52 million for the corresponding period in 2015. These decreases were primarily due to a 52.5% and 47.6% decrease for the second quarter and year-to-date 2016, respectively, in capacity revenues resulting from the expiration of Plant Scherer Unit 3 long-term sales agreements.

Fuel and Purchased Power Expenses

	Second Quarter 2016 vs. Second Quarter 2015					Year-to-Date 2016 vs. Year-to-Date 2015
	(change in millions)			(% change)		(change in millions)			(% change)
Fuel	$	(15	)	(12.3	)	$	(31	)	(13.4	)
Purchased power – non-affiliates	7			28.0		12			24.0
Purchased power – affiliates	(5		)	(55.6	)	(12		)	(70.6	)
Total fuel and purchased power expenses	$	(13	)			$	(31	)

In the second quarter 2016, total fuel and purchased power expenses were $143 million compared to $156 million for the corresponding period in 2015. The decrease was primarily due to a $14 million decrease in the average cost of fuel and purchased power as a result of lower generation from Gulf Power's coal-fired resources.

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GULF POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

For year-to-date 2016, total fuel and purchased power expenses were $268 million compared to $299 million for the corresponding period in 2015. The decrease was primarily the result of a $37 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 $6 million increase related to the volume of KWHs generated and purchased.

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.

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

	Second Quarter 2016	Second Quarter 2015	Year-to-Date 2016	Year-to-Date 2015
Total generation (millions of KWHs)	2,064	2,360	3,880	4,596
Total purchased power (millions of KWHs)	1,629	1,336	3,389	2,594
Sources of generation (percent) –
Coal	54	61	48	60
Gas	46	39	52	40
Cost of fuel, generated (cents per net KWH) –
Coal	4.14	4.05	4.05	4.02
Gas	4.11	4.38	3.92	4.17
Average cost of fuel, generated (cents per net KWH)	4.12	4.18	3.98	4.08
Average cost of purchased power (cents per net KWH)(*)	3.50	4.25	3.35	4.31

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

Fuel

In the second quarter 2016, fuel expense was $107 million compared to $122 million for the corresponding period in 2015. The decrease was primarily due to a 22.5% decrease in the volume of KWHs generated by Gulf Power's coal-fired generation resources and a 1.4% decrease in the average cost of fuel. The decreases were partially offset by a 2.8% increase in the volume of KWHs generated by Gulf Power's gas-fired generation resources.

For year-to-date 2016, fuel expense was $201 million compared to $232 million for the corresponding period in 2015. The decrease was primarily due to a 31.4% decrease in the volume of KWHs generated by Gulf Power's coal-fired generation resources and a 2.5% decrease in the average cost of fuel. The decreases were partially offset by a 7.7% increase in the volume of KWHs generated by Gulf Power's gas-fired generation resources.

Purchased Power – Non-Affiliates

In the second quarter 2016, purchased power expense from non-affiliates was $32 million compared to $25 million for the corresponding period in 2015. The increase was primarily due to a 49.9% increase in the volume of KWHs purchased due to the availability of lower cost energy, partially offset by a 25.8% decrease in the average cost per KWH purchased due to lower energy costs from gas-fired and wind market resources.

For year-to-date 2016, purchased power expense from non-affiliates was $62 million compared to $50 million for the corresponding period in 2015. The increase was primarily due to a 61.8% increase in the volume of KWHs purchased due to the availability of lower cost energy, partially offset by a 29.2% decrease in the average cost per KWH purchased due to lower energy costs from gas-fired and wind market resources.

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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 second quarter 2016, purchased power expense from affiliates was $4 million compared to $9 million for the corresponding period in 2015. The decrease was primarily due to a 47.9% decrease in the volume of KWHs purchased due to lower territorial loads resulting from milder weather and a 22.7% 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.

For year-to-date 2016, purchased power expense from affiliates was $5 million compared to $17 million for the corresponding period in 2015. The decrease was primarily due to a 54.5% decrease in the volume of KWHs purchased due to lower territorial loads resulting from milder weather and a 30.5% 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.

Other Operations and Maintenance Expenses

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$(14)	(15.4)	$(30)	(16.2)

In the second quarter 2016, other operations and maintenance expenses were $77 million compared to $91 million for the corresponding period in 2015. For year-to-date 2016, other operations and maintenance expenses were $155 million compared to $185 million for the corresponding period in 2015. These decreases were primarily due to decreases in routine and planned maintenance expenses at generation facilities and lower expenses related to marketing programs.

Expenses from marketing programs do not have a significant impact on earnings since they are generally offset by energy conservation revenues through Gulf Power's energy conservation cost recovery clause.

Depreciation and Amortization

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$2	5.0	$20	33.3

For year-to-date 2016, depreciation and amortization was $80 million compared to $60 million for the corresponding period in 2015. The increase was primarily due to $13 million less of a reduction in depreciation compared to the corresponding period in 2015, as authorized in the Rate Case Settlement Agreement, as well as 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.

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Allowance for Equity Funds Used During Construction

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$(3)	N/M	$(8)	N/M

N/M - Not meaningful

In the second quarter and year-to-date 2016, AFUDC equity was immaterial compared to $3 million and $8 million for the corresponding periods in 2015, respectively. These decreases were primarily due to environmental control projects at generation facilities and transmission projects 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.

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.

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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 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.

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" in Item 8 of the Form 10-K for additional information.

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 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, long-term non-affiliate capacity sales from Gulf Power's ownership of the unit provided the majority of Gulf Power's wholesale earnings. The revenues from wholesale contracts covering 100% of this capacity represented 82% of wholesale capacity revenues in 2015. Following contract expirations at the end of 2015 and the end of May 2016, Gulf Power's remaining contracted sales from the unit will cover approximately 24% of the unit through 2019. The expiration of these 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. Gulf Power is actively evaluating alternatives, including, 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.

Retail Base Rate Case

In 2013, the Florida PSC approved the Rate Case Settlement Agreement that authorized Gulf Power to reduce depreciation and record a regulatory asset up to $62.5 million from January 2014 through 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 six months of 2016, Gulf Power recognized reductions in depreciation of $8.4 million, $20.1 million, and $6.4 million, respectively.

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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. Gulf Power has filed a petition with the Florida PSC requesting permission to recover the remaining net book value of Plant Smith Units 1 and 2 and the remaining materials and supplies associated with these units as of the retirement date. In connection with this request, Gulf Power reclassified approximately $63 million to a regulatory asset. This amount is comprised of the reclassification of the net book value of these units from other utility plant, net and the associated materials and supplies, both as of March 31, 2016. 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 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.

TheultimateoutcomeofsuchpendingorpotentiallitigationagainstGulf Powercannotbepredictedatthistime;however,forcurrentproceedingsnotspecificallyreportedinNote(B)totheCondensedFinancialStatementshereinorinNote3tothefinancialstatementsofGulf PowerinItem8ofthe 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

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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. Early adoption is permitted and Gulf Power intends to adopt the ASU in the fourth quarter 2016. The adoption is not expected to have a material impact on the results of operations, financial position, or cash flows of Gulf Power.

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 June 30, 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.

Net cash provided from operating activities totaled $195 million for the first six months of 2016 compared to $183 million for the corresponding period in 2015. The $12 million increase in net cash was primarily due to a federal income tax refund and the timing of fossil fuel stock purchases, partially offset by increases in accounts receivable. Net cash used for investing activities totaled $84 million in the first six months of 2016 primarily due to property additions to utility plant. Net cash used for financing activities totaled $139 million for the first six months of 2016 primarily due to the payment of common stock dividends and a redemption of long-term debt, partially offset by an increase in notes payable. Cash flows 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 six months of 2016 include decreases of $125 million in long-term debt due to a redemption and $110 million in net property, plant, and equipment primarily due to the retirement of Plant Smith Units 1 and 2.

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

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interest, leases, derivative obligations, preference stock dividends, purchase commitments, and trust funding requirements. Approximately $195 million will be required through June 30, 2017 to fund maturities 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 significant seasonal fluctuations in cash needs. 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 June 30, 2016, Gulf Power had approximately $46 million of cash and cash equivalents. Committed credit arrangements with banks at June 30, 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)				(in millions)
$	75	$	40	$	165	$	280	$	280	$	45	$	—	$	45	$	70

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

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revenue bonds outstanding requiring liquidity support as of June 30, 2016 was approximately $82 million. In addition, at June 30, 2016, Gulf Power had approximately $21 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 electric 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 June 30, 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	$	87	0.8	%	$	62	0.8	%	$	94
Short-term bank debt	100		1.2	%	54		1.2	%	100
Total	$	187	1.0	%	$	116	1.0	%

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

The maximum potential collateral requirements under these contracts at June 30, 2016 were as follows:

Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB- and/or Baa3	$	137
Below BBB- and/or Baa3	$	526

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 second quarter and year-to-date 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

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

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. Gulf Power is actively evaluating alternatives, including, without limitation, rededication of Gulf Power's ownership of Plant Scherer Unit 3 (205 MWs) 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.

Financing Activities

In May 2016, Gulf Power redeemed $125 million aggregate principal amount of its Series 2011A 5.75% Senior Notes due June 1, 2051.

Also in May 2016, Gulf Power entered into an 11-month floating rate bank loan bearing interest based on one-month LIBOR. This short-term loan was for $100 million aggregate principal amount and the proceeds were used to repay existing indebtedness and for working capital and other general corporate purposes.

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

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MISSISSIPPI POWER COMPANY

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MISSISSIPPI POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2016			2015			2016			2015
	(in millions)						(in millions)
Operating Revenues:
Retail revenues	$	206		$	189		$	389		$	357
Wholesale revenues, non-affiliates	60			63			120			141
Wholesale revenues, affiliates	7			18			16			45
Other revenues	4			5			8			9
Total operating revenues	277			275			533			552
Operating Expenses:
Fuel	81			115			157			229
Purchased power, non-affiliates	1			2			1			3
Purchased power, affiliates	4			2			9			4
Other operations and maintenance	68			68			136			144
Depreciation and amortization	45			30			84			57
Taxes other than income taxes	25			23			50			48
Estimated loss on Kemper IGCC	81			23			134			32
Total operating expenses	305			263			571			517
Operating Income (Loss)	(28		)	12			(38		)	35
Other Income and (Expense):
Allowance for equity funds used during construction	30			25			59			53
Interest expense, net of amounts capitalized	(15		)	30			(31		)	19
Other income (expense), net	(1		)	(1		)	(3		)	(2		)
Total other income and (expense)	14			54			25			70
Earnings (Loss) Before Income Taxes	(14		)	66			(13		)	105
Income taxes (benefit)	(17		)	16			(27		)	20
Net Income	3			50			14			85
Dividends on Preferred Stock	1			1			1			1
Net Income After Dividends on Preferred Stock	$	2		$	49		$	13		$	84

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2016		2015		2016		2015
	(in millions)				(in millions)
Net Income	$	3	$	50	$	14	$	85
Other comprehensive income (loss)	—		—		—		—
Comprehensive Income	$	3	$	50	$	14	$	85

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

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CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Six Months Ended June 30,
	2016			2015
	(in millions)
Operating Activities:
Net income	$	14		$	85
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	82			55
Deferred income taxes	(16		)	694
Investment tax credits	—			32
Allowance for equity funds used during construction	(59		)	(53		)
Regulatory assets associated with Kemper IGCC	(10		)	(50		)
Estimated loss on Kemper IGCC	134			32
Income taxes receivable, non-current	—			(544		)
Other, net	3			8
Changes in certain current assets and liabilities —
-Receivables	15			6
-Fossil fuel stock	6			5
-Prepaid income taxes	34			24
-Other current assets	(3		)	(7		)
-Accounts payable	(12		)	(25		)
-Accrued taxes	19			(51		)
-Accrued interest	—			(7		)
-Accrued compensation	(12		)	(12		)
-Over recovered regulatory clause revenues	4			32
-Mirror CWIP	—			82
-Customer liability associated with Kemper refunds	(69		)	—
-Other current liabilities	7			3
Net cash provided from operating activities	137			309
Investing Activities:
Property additions	(403		)	(428		)
Construction payables	(11		)	(15		)
Capital grant proceeds	137			—
Other investing activities	(19		)	(17		)
Net cash used for investing activities	(296		)	(460		)
Financing Activities:
Increase in notes payable, net	—			475
Proceeds —
Capital contributions from parent company	226			77
Long-term debt issuance to parent company	200			—
Other long-term debt issuances	900			—
Short-term borrowings	—			30
Redemptions —
Short-term borrowings	(475		)	—
Long-term debt to parent company	(225		)	—
Other long-term debt	(425		)	(350		)
Other financing activities	(3		)	(2		)
Net cash provided from financing activities	198			230
Net Change in Cash and Cash Equivalents	39			79
Cash and Cash Equivalents at Beginning of Period	98			133
Cash and Cash Equivalents at End of Period	$	137		$	212
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (paid $49 and $39, net of $23 and $37 capitalized for 2016 and 2015, respectively)	$	26		$	2
Income taxes, net	(122		)	(181		)
Noncash transactions —
Accrued property additions at end of period	94			99
Issuance of promissory note to parent related to repayment of     interest-bearing refundable deposits and accrued interest	—			301

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 June 30, 2016		At December 31, 2015
	(in millions)
Current Assets:
Cash and cash equivalents	$	137	$	98
Receivables —
Customer accounts receivable	35		26
Unbilled revenues	46		36
Income taxes receivable, current	—		20
Other accounts and notes receivable	5		10
Affiliated companies	12		20
Fossil fuel stock, at average cost	99		104
Materials and supplies, at average cost	77		75
Other regulatory assets, current	97		95
Prepaid income taxes	5		39
Other current assets	7		8
Total current assets	520		531
Property, Plant, and Equipment:
In service	4,809		4,886
Less accumulated provision for depreciation	1,248		1,262
Plant in service, net of depreciation	3,561		3,624
Construction work in progress	2,429		2,254
Total property, plant, and equipment	5,990		5,878
Other Property and Investments	11		11
Deferred Charges and Other Assets:
Deferred charges related to income taxes	317		290
Other regulatory assets, deferred	520		525
Income taxes receivable, non-current	544		544
Other deferred charges and assets	85		61
Total deferred charges and other assets	1,466		1,420
Total Assets	$	7,987	$	7,840

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

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MISSISSIPPI POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholder's Equity	At June 30, 2016			At December 31, 2015
	(in millions)
Current Liabilities:
Securities due within one year	$	343		$	728
Notes payable	25			500
Accounts payable —
Affiliated	87			85
Other	120			135
Customer deposits	16			16
Accrued taxes —
Accrued income taxes	57			—
Other accrued taxes	48			85
Accrued interest	19			18
Accrued compensation	14			26
Asset retirement obligations, current	21			22
Over recovered regulatory clause liabilities	100			96
Customer liability associated with Kemper refunds	5			73
Other current liabilities	41			52
Total current liabilities	896			1,836
Long-term Debt:
Long-term debt, affiliated	551			576
Long-term debt, non-affiliated	2,164			1,310
Total Long-term Debt	2,715			1,886
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	773			762
Deferred credits related to income taxes	8			8
Accumulated deferred investment tax credits	5			5
Employee benefit obligations	148			153
Asset retirement obligations, deferred	157			154
Unrecognized tax benefits	368			368
Other cost of removal obligations	169			165
Other regulatory liabilities, deferred	74			71
Other deferred credits and liabilities	40			40
Total deferred credits and other liabilities	1,742			1,726
Total Liabilities	5,353			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	3,122			2,893
Accumulated deficit	(553		)	(566		)
Accumulated other comprehensive loss	(6		)	(6		)
Total common stockholder's equity	2,601			2,359
Total Liabilities and Stockholder's Equity	$	7,987		$	7,840

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

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

SECOND QUARTER 2016 vs. SECOND QUARTER 2015

AND

YEAR-TO-DATE 2016 vs. YEAR-TO-DATE 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 progress towards completing the remainder of the Kemper IGCC, including the gasifiers and the gas clean-up facilities. The in-service date for the remainder of the Kemper IGCC is currently expected to occur by October 31, 2016, which reflects a one-month extension. The initial production of syngas began on July 14, 2016 and testing has continued on gasifier 'B' and the related lignite feed and ash systems. The schedule extension provides for time to complete mechanical equipment modifications to the gasifiers' supporting systems to increase capacity to the levels necessary to complete the remaining start-up activities and achieve sustained operations on both gasifiers. The remaining schedule also reflects the time expected to complete the initial operation and testing of the facility's syngas clean-up systems, as well as the integration of all systems necessary for both combustion turbines to simultaneously generate electricity with syngas.

Mississippi Power's current cost estimate for the Kemper IGCC in total is approximately $6.68 billion, which includes approximately $5.43 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 totaling $81 million ($50 million after tax) in the second quarter 2016 and a total of $134 million ($83 million after tax) for the six months ended June 30, 2016. Since 2012, in the aggregate, Mississippi Power has incurred charges of $2.55 billion ($1.57 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through June 30, 2016. The current cost estimate includes costs through October 31, 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

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

that provide for the recovery of approximately $126 million annually related to Kemper IGCC assets previously placed in service. On July 27, 2016, the Mississippi Supreme Court (Court) dismissed Greenleaf CO₂ Solutions, LLC’s (Greenleaf) motion for reconsideration of its previous decision to dismiss Greenleaf's appeal of the In-Service Asset Rate Order. 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 by October 31, 2016. The ultimate outcome of these matters cannot be determined at this time.

Southern Company and Mississippi Power are defendants in lawsuits that allege improper disclosure of important facts about the Kemper IGCC. One lawsuit was filed in Harrison County Circuit Court by Biloxi Freezing & Processing Inc., Gulfside Casino Partnership, and John Carlton Dean and seeks unspecified actual damages, punitive damages, and attorney's fees, costs, and interest. Another lawsuit was filed by Treetop Midstream Services, LLC (Treetop) and other related parties and seeks $100 million in compensatory damages, as well as punitive damages, costs, and interest. While Mississippi Power believes that these lawsuits are without merit, an adverse outcome could have a material impact on Mississippi Power's results of operations, financial condition, and liquidity. In addition, 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.

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

On March 8, 2016, Mississippi Power borrowed $900 million under a new term loan agreement with a syndicate of financial institutions and used the proceeds to repay $900 million in maturing bank loans. Mississippi Power has the right to borrow the $300 million remaining under the agreement on or before October 15, 2016 and expects to use those funds to repay senior notes maturing in October 2016. On June 27, 2016, Mississippi Power received a $225 million capital contribution from Southern Company which was used to repay to Southern Company a portion of an existing promissory note.

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

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$(47)	(95.9)	$(71)	(84.5)

Mississippi Power's net income after dividends on preferred stock for the second quarter 2016 was $2 million compared to $49 million for the corresponding period in 2015. The decrease was primarily related to higher pre-tax charges of $81 million ($50 million after tax) in the second quarter 2016 compared to pre-tax charges of $23 million ($14 million after tax) in the second quarter 2015 for revisions of the estimated costs expected to be incurred on

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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 due to a decrease in interest on deposits resulting from the termination of an asset purchase agreement between Mississippi Power and SMEPA in May 2015. Also contributing to the decrease was higher depreciation and amortization and a decrease in wholesale revenues, partially offset by an increase in retail revenues.

For year-to-date 2016, net income after dividends on preferred stock was $13 million compared to $84 million for the corresponding period in 2015. The decrease was primarily related to higher pre-tax charges of $134 million ($83 million after tax) in 2016 compared to pre-tax charges of $32 million ($20 million after tax) in 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 due to a decrease in interest on deposits resulting from the termination of an asset purchase agreement between Mississippi Power and SMEPA in May 2015. Also contributing to the decrease was higher depreciation and amortization and a decrease in wholesale revenues, partially offset by an increase in retail revenues.

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

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$17	9.0	$32	9.0

In the second quarter 2016, retail revenues were $206 million compared to $189 million for the corresponding period in 2015. For year-to-date 2016, retail revenues were $389 million compared to $357 million for the corresponding period in 2015.

Details of the changes in retail revenues were as follows:

	Second Quarter 2016					Year-to-Date 2016
	(in millions)			(% change)		(in millions)			(% change)
Retail – prior year	$	189				$	357
Estimated change resulting from –
Rates and pricing	32			16.9		57			16.0
Sales growth (decline)	(1		)	(0.5	)	3			0.8
Weather	1			0.5		(2		)	(0.6	)
Fuel and other cost recovery	(15		)	(7.9	)	(26		)	(7.2	)
Retail – current year	$	206		9.0	%	$	389		9.0	%

Revenues associated with changes in rates and pricing increased in the second quarter and year-to-date 2016 when compared to the corresponding periods 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" 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.

Revenues attributable to changes in sales decreased in the second quarter 2016 when compared to the corresponding period in 2015. Weather-adjusted KWH sales to residential and commercial customers decreased 2.2% and 4.0%, respectively, in the second quarter 2016 due to decreased customer usage, partially offset by customer growth.

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MISSISSIPPI POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

KWH sales to industrial customers increased 2.9% in the second quarter 2016 due to increased usage by larger customers.

Revenues attributable to changes in sales were relatively flat for year-to-date 2016 when compared to the corresponding period in 2015. Weather-adjusted KWH sales to commercial customers decreased 1.9% due to decreased customer usage, partially offset by customer growth. KWH sales to industrial customers and weather-adjusted KWH sales to residential customers were relatively flat.

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, year-to-date 2016 weather-adjusted residential KWH sales increased 3.0%, weather-adjusted KWH sales to commercial customers increased 1.6%, and KWH sales to industrial customers increased 1.0% as compared to the corresponding period in 2015.

Fuel and other cost recovery revenues decreased in the second quarter and year-to-date 2016 when compared to the corresponding periods 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

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$(3)	(4.8)	$(21)	(14.9)

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 provides service under long-term contracts with rural electric cooperative associations and municipalities located in 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 second quarter 2016, wholesale revenues from sales to non-affiliates were $60 million compared to $63 million for the corresponding period in 2015. The decrease was primarily due to a $6 million decrease in energy revenues primarily resulting from lower fuel prices, partially offset by a $3 million increase in base and capacity revenues primarily resulting from a wholesale rate increase. For year-to-date 2016, wholesale revenues from sales to non-affiliates were $120 million compared to $141 million for the corresponding period in 2015. The decrease was primarily due to a $14 million decrease in energy revenues primarily resulting from lower fuel prices and decreased usage and a $7 million decrease in base and capacity revenues primarily resulting from milder weather.

102

MISSISSIPPI POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Wholesale Revenues – Affiliates

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$(11)	(61.1)	$(29)	(64.4)

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 second quarter 2016, wholesale revenues from sales to affiliates were $7 million compared to $18 million for the corresponding period in 2015. The decrease was due to a $9 million decrease in KWH sales resulting from a decrease in sales from coal generation and a $2 million decrease associated with lower natural gas prices.

For year-to-date 2016, wholesale revenues from sales to affiliates were $16 million compared to $45 million for the corresponding period in 2015. The decrease was due to a $23 million decrease in KWH sales resulting from a decrease in sales from coal generation and a $6 million decrease associated with lower natural gas prices.

Fuel and Purchased Power Expenses

	Second Quarter 2016 vs. Second Quarter 2015				Year-to-Date 2016 vs. Year-to-Date 2015
	(change in millions)			(% change)	(change in millions)			(% change)
Fuel	$	(34	)	(29.6)	$	(72	)	(31.4	)
Purchased power – non-affiliates	(1		)	(50.0)	(2		)	(66.7	)
Purchased power – affiliates	2			100.0	5			125.0
Total fuel and purchased power expenses	$	(33	)		$	(69	)

In the second quarter 2016, total fuel and purchased power expenses were $86 million compared to $119 million for the corresponding period in 2015. The decrease was due to a $16 million decrease in the volume of KWHs generated and purchased and a $17 million decrease in the average cost of fuel.

For year-to-date 2016, total fuel and purchased power expenses were $167 million compared to $236 million for the corresponding period in 2015. The decrease was due to a $34 million decrease in the volume of KWHs generated and purchased and a $35 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.

103

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:

	Second Quarter 2016	Second Quarter 2015	Year-to-Date 2016	Year-to-Date 2015
Total generation (millions of KWHs)	3,728	4,109	7,315	8,455
Total purchased power (millions of KWHs)	188	114	449	227
Sources of generation (percent) –
Coal	5	18	8	20
Gas	95	82	92	80
Cost of fuel, generated (cents per net KWH) –
Coal	5.49	4.14	4.16	3.64
Gas	2.17	2.71	2.16	2.69
Average cost of fuel, generated (cents per net KWH)	2.33	2.98	2.32	2.90
Average cost of purchased power (cents per net KWH)	2.55	3.19	2.33	3.37

Fuel

In the second quarter 2016, fuel expense was $81 million compared to $115 million for the corresponding period in 2015. The decrease was due to a 10% decrease in the volume of KWHs generated, primarily as a result of milder weather, and a 22% 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 76% and an increase in gas-fired generation of 5%.

For year-to-date 2016, total fuel expense was $157 million compared to $229 million for the corresponding period in 2015. The decrease was due to a 15% decrease in the volume of KWHs generated, primarily as a result of milder weather, and a 20% 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 also included a 68% decrease in coal-fired generation.

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

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$—	—	$(8)	(5.6)

For year-to-date 2016, other operations and maintenance expenses were $136 million compared to $144 million for the corresponding period in 2015. The decrease was primarily due to a $16 million decrease in generation outage costs, a $4 million decrease primarily related to pension costs, a $2 million decrease in transmission and distribution overhead line maintenance and vegetation management, and a $2 million decrease in uncollectibles expense and customer incentives. The decreases were partially offset by a $16 million increase in 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

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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.

Depreciation and Amortization

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$15	50.0	$27	47.4

In the second quarter 2016, depreciation and amortization was $45 million compared to $30 million for the corresponding period in 2015. For year-to-date 2016, depreciation and amortization was $84 million compared to $57 million for the corresponding period in 2015. These increases were primarily due to additional amortization expenses and lower deferrals associated with the Kemper IGCC combined cycle assets of $13 million and $22 million in the second quarter and year-to-date 2016, respectively, in accordance with the In-Service Asset Rate Order. Additionally, increases of $2 million and $5 million in the second quarter and year-to-date 2016, respectively, are related to additional plant in service.

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 – Rate Recovery of Kemper IGCC Costs – 2015 Rate Case" and " – Regulatory Assets and Liabilities" herein for additional information.

Estimated Loss on Kemper IGCC

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$58	N/M	$102	N/M

N/M - Not meaningful

In the second quarters of 2016 and 2015, estimated probable losses on the Kemper IGCC of $81 million and $23 million, respectively, were recorded at Mississippi Power. For year-to-date 2016 and year-to-date 2015, estimated probable losses on the Kemper IGCC of $134 million and $32 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.

Allowance for Equity Funds Used During Construction

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$5	20.0	$6	11.3

In the second quarter of 2016, AFUDC equity was $30 million compared to $25 million for the corresponding period in 2015. For year-to-date 2016, AFUDC equity was $59 million compared to $53 million for the corresponding period in 2015. The increase was driven by a higher AFUDC equity rate and an increase in Kemper IGCC AFUDC, primarily associated with the wholesale settlement agreement removing all Kemper IGCC CWIP from rate base, partially offset by placing the Plant Daniel scrubbers in service in November 2015. See Note 3 to the

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

Interest Expense, Net of Amounts Capitalized

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$45	N/M	$50	N/M

N/M - Not meaningful

In the second quarter 2016, interest expense, net of amounts capitalized was $15 million compared to $(30) million for the corresponding period in 2015. For year-to-date 2016, interest expense, net of amounts capitalized was $31 million compared to $(19) million for the corresponding period in 2015. The increases were primarily due to a $38 million and a $31 million decrease for the second quarter and year-to-date 2016, respectively, in interest on deposits resulting from the termination of an asset purchase agreement between Mississippi Power and SMEPA in May 2015. In addition, these increases were related to additional long-term debt and decreases in amounts capitalized, partially offset by a decrease in interest on 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.

Income Taxes (Benefit)

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$(33)	N/M	$(47)	N/M

N/M - Not meaningful

In the second quarter 2016, income tax benefit was $(17) million compared to an expense of $16 million for the corresponding period in 2015. For year-to-date 2016, income tax benefit was $(27) million compared to an expense of $20 million for the corresponding period in 2015. The changes were primarily due to the reduction in pre-tax earnings related to the estimated probable losses on 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 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

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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 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 reached a settlement agreement with its wholesale customers and filed a request with the FERC for an increase in wholesale base revenues under the Municipal and Rural Associations (MRA) cost-based electric tariff. The settlement agreement, accepted by the FERC, effective for services rendered beginning May 1, 2016, provides that base rates under the MRA cost-based electric tariff will produce additional annual base revenues of $7 million. 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 to similar regulatory treatment for MRA tariff ratemaking as the treatment approved for retail ratemaking under the In-Service Asset Rate Order. This regulatory treatment primarily includes (i) recovery of the Kemper IGCC assets currently operational and providing service to customers and other related costs, (ii) amortization of the Kemper IGCC-related regulatory assets included in rates under the settlement agreement over 36 months, (iii) Kemper IGCC-related expenses included in rates under the settlement agreement no longer being deferred and charged to

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expense, and (iv) removing all of the Kemper IGCC CWIP from rate base with a corresponding increase in accrual of AFUDC. The additional resulting AFUDC is estimated to be approximately $8 million through the Kemper IGCC's projected in-service date of October 31, 2016.

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.

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. The projects are expected to be in service by the second quarter 2017 and the resulting energy purchases are expected to be recovered through Mississippi Power's fuel cost recovery mechanism. Mississippi Power may retire the renewable energy credits (REC) generated on behalf of its customers or sell the RECs, separately or bundled with energy, to third parties.

Energy Efficiency

On May 3, 2016, the Mississippi PSC issued an order approving the annual Energy Efficiency Cost Rider Compliance filing, which included an anticipated reduction of $2 million in retail revenues for the year ending December 31, 2016.

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.

On July 12, 2016, Mississippi Power submitted its annual projected PEP filing for 2016 which indicated no change in rates.

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

Fuel Cost Recovery

At June 30, 2016, the amount of over-recovered retail fuel costs included on the balance sheet was $76 million compared to $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.

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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 expected 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 in August 2014 and continues to progress towards completing the remainder of the Kemper IGCC, including the gasifiers and the gas clean-up facilities. The in-service date for the remainder of the Kemper IGCC is currently expected to occur by October 31, 2016, which reflects a one-month extension. The initial production of syngas began on July 14, 2016 and testing has continued on gasifier 'B' and the related lignite feed and ash systems. The schedule extension provides for time to complete mechanical equipment modifications to the gasifiers' supporting systems to increase capacity to the levels necessary to complete the remaining start-up activities and achieve sustained operations on both gasifiers. The remaining schedule also reflects the time expected to complete the initial operation and testing of the facility's syngas clean-up systems, as well as the integration of all systems necessary for both combustion turbines to simultaneously generate electricity with syngas.

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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 June 30, 2016, are as follows:

Cost Category	2010 Project Estimate(a)		Current Cost Estimate(b)			Actual Costs
	(in billions)
Plant Subject to Cost Cap(c)(e)	$	2.40	$	5.43		$	5.15
Lignite Mine and Equipment	0.21		0.23			0.23
CO2 Pipeline Facilities	0.14		0.11			0.12
AFUDC(d)	0.17		0.72			0.66
Combined Cycle and Related Assets Placed in Service – Incremental(e)	—		0.03			0.02
General Exceptions	0.05		0.10			0.09
Deferred Costs(e)	—		0.20			0.19
Additional DOE Grants	—		(0.14		)	(0.14		)
Total Kemper IGCC	$	2.97	$	6.68		$	6.32

(a) 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, as well as the lignite mine and equipment, AFUDC, and general exceptions.

(b) Amounts in the Current Cost Estimate reflect estimated costs through October 31, 2016.

(c) 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 (e) for additional information.

(d) Mississippi Power's 2010 Project Estimate included recovery of financing costs during construction rather than the accrual of AFUDC. This approach was not approved by the Mississippi PSC as described in "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order." The Current Cost Estimate also 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.

(e) Non-capital Kemper IGCC-related costs incurred during construction were initially deferred as regulatory assets. Some of these costs are now included in rates and are being recognized through income; however such costs continue to be included in the Current Cost Estimate and the Actual Costs at June 30, 2016. The wholesale portion of debt carrying costs, whether deferred or recognized through income, are not included in the Current Cost Estimate and the Actual Costs at June 30, 2016. See "Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities" herein for additional information.

Of the total costs, including post-in-service costs for the lignite mine, incurred as of June 30, 2016, $3.59 billion was included in property, plant, and equipment (which is net of the Initial DOE Grants, the Additional DOE Grants, and estimated probable losses of $2.55 billion), $6 million in other property and investments, $81 million in fossil fuel stock, $46 million in materials and supplies, $35 million in other regulatory assets, current, $180 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 of $81 million($50 million after tax) in the second quarter 2016 and a total of $134 million ($83 million after tax) for the six months ended June 30, 2016. Since 2012, in the aggregate, Mississippi Power has incurred charges of $2.55 billion ($1.57 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through June 30, 2016. The increase to the cost estimate in 2016 primarily reflects costs for the extension of the Kemper IGCC's projected in-service date through October 31, 2016 and increased efforts related to operational readiness and challenges in

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start-up and commissioning activities, which includes the cost of repairs and modifications associated with the lignite feed process and the refractory lining for the gasifiers. Any extension of the in-service date beyond October 31, 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 October 31, 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 $3 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. Significant testing activities, including those for coal feed and gasification systems, as well as the initial operation and testing of the facility's gas clean-up systems and production of clean syngas, and, ultimately the generation of electricity, remain in process. Further cost increases and/or extensions of the expected in-service date may result from factors including, but not limited to, difficulties integrating the systems required for sustained operations, major equipment failure, unforeseen engineering or design problems including any repairs and/or modifications to systems, and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC). 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.

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-

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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

On August 13, 2015, the Mississippi PSC approved Mississippi Power's request for interim rates, 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. The interim rates were designed to collect approximately $159 million annually and became 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 rates 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.

On July 27, 2016, the Court dismissed Greenleaf's motion for reconsideration of its previous decision to dismiss Greenleaf's appeal of the In-Service Asset Rate Order.

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.

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

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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 June 30, 2016 of $6.68 billion, Mississippi Power anticipates that it will incur additional expenses in excess of current rates associated with operating the Kemper IGCC after it is placed in service until the Kemper IGCC cost recovery approach is finalized, which are expected to be material. These costs include, but are not limited to, regulatory costs, operational costs in excess of current rates, and additional carrying costs. Mississippi Power will seek approval from the Mississippi PSC to defer these costs for future rate recovery to be determined in connection with the final Kemper IGCC cost recovery approach ultimately approved. See "Regulatory Assets and Liabilities" below for additional information.

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 and second quarter 2016, in connection with the implementation of retail and wholesale rates, respectively, Mississippi Power began expensing certain ongoing project costs and certain retail 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 and the settlement agreement with wholesale customers. As of June 30, 2016, the balance associated with these regulatory assets was $114 million, of which $35 million is included in current assets. Other regulatory assets associated with the remainder of the Kemper IGCC totaled $101 million as of June 30, 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. Also see "FERC Matters" herein for information related to the 2016 settlement agreement with wholesale customers.

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. At June 30, 2016, Mississippi Power's related regulatory liability included in its balance sheet totaled approximately $5 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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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 entered into agreements with Denbury Onshore (Denbury) and Treetop Midstream Services, LLC, pursuant to which Denbury would purchase 70% of the CO₂ captured from the Kemper IGCC and Treetop would purchase 30% of the CO₂ captured from the Kemper IGCC. On June 3, 2016, Mississippi Power cancelled its contract with Treetop and amended its contract with Denbury to reflect, among other things, Denbury's agreement to purchase 100% of the CO₂ captured from the Kemper IGCC, an initial contract term of 16 years, and termination rights if Mississippi Power has not satisfied its contractual obligation to deliver captured CO₂ by July 1, 2017, in addition to Denbury's existing termination rights in the event of a change in law, force majeure, or an event of default by Mississippi Power. Any termination or material modification of the agreement with Denbury could impact the operations of the Kemper IGCC and 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 or otherwise sequester the CO₂ produced. Additionally, 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.

Litigation

On April 26, 2016, a complaint against Mississippi Power was filed in Harrison County Circuit Court (Circuit Court) by Biloxi Freezing & Processing Inc., Gulfside Casino Partnership, and John Carlton Dean, which was amended and refiled on July 11, 2016 to include, among other things, Southern Company as a defendant. The individual plaintiff, John Carlton Dean, alleges that Mississippi Power and Southern Company violated the Mississippi Unfair Trade Practices Act. All plaintiffs have alleged that Mississippi Power and Southern Company concealed, falsely represented, and failed to fully disclose important facts concerning the cost and schedule of the Kemper IGCC and that these alleged breaches have unjustly enriched Mississippi Power and Southern Company. The plaintiffs seek unspecified actual damages and punitive damages; ask the Circuit Court to appoint a receiver to oversee, operate, manage, and otherwise control all affairs relating to the Kemper IGCC; ask the Circuit Court to revoke any licenses or certificates authorizing Mississippi Power or Southern Company to engage in any business related to the Kemper IGCC in Mississippi; and seek 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.

On June 9, 2016, Treetop, Greenleaf, Tenrgys, LLC, Tellus Energy, LLC, WCOA, LLC, and Tellus Operating Group filed a complaint against Mississippi Power, Southern Company, and SCS in the state court in Gwinnett County, Georgia. The complaint relates to the cancelled CO₂ contract with Treetop and alleges fraudulent misrepresentation, fraudulent concealment, civil conspiracy, and breach of contract on the part of Mississippi Power, Southern Company, and SCS and seeks compensatory damages of $100 million, as well as unspecified punitive damages.

Mississippi Power believes these legal challenges have no merit; however, an adverse outcome in these proceedings could have a material impact on Mississippi Power's results of operations, financial condition, and liquidity. Mississippi Power will vigorously defend itself in these matters, and the ultimate outcome of these matters cannot be determined at this time.

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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.

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. 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

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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 $81 million ($50 million after tax) in the second quarter 2016, $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, $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 $2.55 billion ($1.57 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through June 30, 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. Further cost increases and/or extensions of the expected in-service date may result from factors including, but not limited to, difficulties integrating the systems required for sustained operations, major equipment failure, unforeseen engineering or design problems including any repairs and/or modifications to systems, and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC).

Mississippi Power's revised cost estimate includes costs through October 31, 2016. Any extension of the in-service date beyond October 31, 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 October 31, 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 $3 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.

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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. 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. Early adoption is permitted and Mississippi Power intends to adopt the ASU in the fourth quarter 2016. The adoption is not expected to have a material impact on the results of operations, financial position, or cash flows of Mississippi Power.

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 six months ended June 30, 2016 were negatively affected by revisions to the cost estimate for the Kemper IGCC.

Through June 30, 2016, Mississippi Power has incurred non-recoverable cash expenditures of $2.28 billion and is expected to incur approximately $0.27 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 six months of 2016, Mississippi Power borrowed from Southern Company $100 million under this promissory note and an additional $100 million under a separate promissory note issued in November 2015. On March 8, 2016, Mississippi Power entered into an unsecured term loan agreement with a syndicate of financial institutions for an aggregate amount of $1.2 billion. 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. On June 27, 2016, Mississippi Power received a capital contribution from Southern Company for $225 million, the proceeds of which were used to repay to Southern Company a portion of the existing promissory note issued in November 2015. As of June 30, 2016, the amount of outstanding promissory notes to Southern Company totaled $551 million.

As of June 30, 2016, Mississippi Power's current liabilities exceeded current assets by approximately $376 million primarily due to $300 million in senior notes scheduled to mature on October 15, 2016, $40 million of variable rate pollution control revenue bonds backed by short-term credit facilities, and $25 million in short-term debt. Mississippi Power intends to utilize operating cash flows, the remaining $300 million under the term loan, 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 provided from operating activities totaled $137 million for the first six months of 2016, a decrease of $172 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 (R&E) tax deductions and the cessation of Mirror CWIP collections and subsequent refund payments, partially offset by income taxes receivable associated with R&E deductions and accrued taxes. See Notes (B) and (G) to the Condensed Financial Statements under "Integrated Coal

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Gasification Combined Cycle – Rate Recovery of Kemper IGCC Costs" and "Unrecognized Tax Benefits – Section 174 Research and Experimental Deduction" herein for additional information. Net cash used for investing activities totaled $296 million for the first six months of 2016 primarily due to receipt of $137 million in Additional DOE Grants for the Kemper IGCC and gross property additions related to the Kemper IGCC. Net cash provided from financing activities totaled $198 million for the first six months of 2016 primarily due to long-term debt issuances and capital contributions from Southern Company, partially offset by redemptions of long-term debt and short-term borrowings. Cash flows 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 six months of 2016 include an increase in long-term debt of $829 million. A portion of this debt was used to repay securities and notes payable resulting in a $385 million decrease in securities due within one year and a $475 million decrease in notes payable. Additionally, CWIP increased $175 million primarily due to the Kemper IGCC and the customer liability associated with Kemper IGCC refunds decreased $68 million. Total common stockholder's equity increased $242 million primarily due to the receipt of capital contributions from Southern Company and net income for the period.

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 June 30, 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 $920 million for 2016, $218 million for 2017, and $264 million for 2018, which includes expenditures related to the construction of the Kemper IGCC of $745 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.

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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.

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 six months of 2016, Mississippi Power borrowed from Southern Company $100 million pursuant to the $275 million promissory note with a $50 million draw occurring on each of January 29, 2016 and March 14, 2016, and an additional $100 million under a separate promissory note issued in November 2015. On March 8, 2016, Mississippi Power entered into an unsecured term loan agreement with a syndicate of financial institutions for an aggregate amount of $1.2 billion. 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. On June 27, 2016, Mississippi Power received a capital contribution from Southern Company for $225 million, the proceeds of which were used to repay to Southern Company a portion of the existing promissory note issued in November 2015. As of June 30, 2016, the amount of outstanding promissory notes to Southern Company totaled $551 million.

Mississippi Power intends to utilize operating cash flows, the remaining $300 million under the term loan, 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 June 30, 2016, Mississippi Power had approximately $137 million of cash and cash equivalents. Committed credit arrangements with banks at June 30, 2016 were as follows:

Expires								Executable Term Loans				Due Within One Year
2016		2017		Total		Unused		One Year		Two Years		Term Out		No Term Out
(in millions)				(in millions)				(in millions)				(in millions)
$	115	$	60	$	175	$	150	$	—	$	15	$	15	$	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.

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A portion of the $150 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 June 30, 2016 was approximately $40 million.

Details of short-term borrowings were as follows:

	Short-term Debt at June 30, 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	2.2%	$	25	2.1%	$	25

(*) Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 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 June 30, 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 $251 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.

On May 12, 2016, Fitch downgraded the senior unsecured long-term debt rating of Mississippi Power to BBB+ from A- and revised the ratings outlook from negative to stable.

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 June 30, 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 June 27, 2016, Mississippi Power received a capital contribution from Southern Company of $225 million, the proceeds of which were used to repay to Southern Company a portion of the existing promissory note issued in November 2015. As of June 30, 2016, the amount of outstanding promissory notes to Southern Company totaled $551 million.

On March 8, 2016, Mississippi Power entered into an unsecured term loan agreement with a syndicate of financial institutions 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

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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.

In June 2016, Mississippi Power renewed a $10 million short-term note, which matures on June 30, 2017, bearing interest based on three-month LIBOR.

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SOUTHERN POWER COMPANY

AND SUBSIDIARY COMPANIES

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CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2016			2015			2016			2015
	(in millions)						(in millions)
Operating Revenues:
Wholesale revenues, non-affiliates	$	264		$	250		$	480		$	481
Wholesale revenues, affiliates	107			85			204			199
Other revenues	2			2			4			4
Total operating revenues	373			337			688			684
Operating Expenses:
Fuel	96			105			187			243
Purchased power, non-affiliates	21			18			35			34
Purchased power, affiliates	2			4			8			14
Other operations and maintenance	86			69			162			121
Depreciation and amortization	81			60			154			118
Taxes other than income taxes	6			6			13			12
Total operating expenses	292			262			559			542
Operating Income	81			75			129			142
Other Income and (Expense):
Interest expense, net of amounts capitalized	(22		)	(23		)	(43		)	(45		)
Other income (expense), net	1			1			1			1
Total other income and (expense)	(21		)	(22		)	(42		)	(44		)
Earnings Before Income Taxes	60			53			87			98
Income taxes (benefit)	(41		)	1			(65		)	13
Net Income	101			52			152			85
Less: Net income attributable to noncontrolling interests	12			6			13			6
Net Income Attributable to Southern Power	$	89		$	46		$	139		$	79

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended June 30,					For the Six Months Ended June 30,
	2016			2015		2016			2015
	(in millions)					(in millions)
Net Income	$	101		$	52	$	152		$	85
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(15), $-, $(15) and $-, respectively	(24		)	—		(24		)	—
Reclassification adjustment for amounts included in net income, net of tax of $8, $-, $8, and $-, respectively	13			—		14			—
Total other comprehensive income (loss)	(11		)	—		(10		)	—
Less: Comprehensive income attributable to noncontrolling interests	12			6		13			6
Comprehensive Income Attributable to Southern Power	$	78		$	46	$	129		$	79

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

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Six Months Ended June 30,
	2016			2015
	(in millions)
Operating Activities:
Net income	$	152		$	85
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	159			121
Deferred income taxes	(71		)	59
Investment tax credits	—			153
Amortization of investment tax credits	(15		)	(10		)
Deferred revenues	(31		)	(21		)
Accrued income taxes, non-current	—			100
Other, net	9			10
Changes in certain current assets and liabilities —
-Receivables	(76		)	(26		)
-Prepaid income taxes	(147		)	(102		)
-Other current assets	5			5
-Accounts payable	4			(31		)
-Accrued taxes	62			(110		)
-Other current liabilities	—			18
Net cash provided from operating activities	51			251
Investing Activities:
Business acquisitions	(502		)	(408		)
Property additions	(1,281		)	(154		)
Change in construction payables	(137		)	38
Payments pursuant to long-term service agreements	(43		)	(45		)
Investment in restricted cash	(646		)	—
Distribution of restricted cash	649			—
Other investing activities	(25		)	(1		)
Net cash used for investing activities	(1,985		)	(570		)
Financing Activities:
Increase (decrease) in notes payable, net	695			(195		)
Proceeds —
Senior notes	1,241			650
Capital contributions	300			—
Distributions to noncontrolling interests	(11		)	(1		)
Capital contributions from noncontrolling interests	179			78
Purchase of membership interests from noncontrolling interests	(129		)	—
Payment of common stock dividends	(136		)	(65		)
Other financing activities	(13		)	(3		)
Net cash provided from financing activities	2,126			464
Net Change in Cash and Cash Equivalents	192			145
Cash and Cash Equivalents at Beginning of Period	830			75
Cash and Cash Equivalents at End of Period	$	1,022		$	220
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $21 and $1 capitalized for 2016 and 2015, respectively)	$	42		$	35
Income taxes, net	115			(72		)
Noncash transactions — Accrued property additions at end of period	108			38

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

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CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

Assets	At June 30, 2016		At December 31, 2015
	(in millions)
Current Assets:
Cash and cash equivalents	$	1,022	$	830
Receivables —
Customer accounts receivable	115		75
Other accounts receivable	23		19
Affiliated companies	60		30
Fossil fuel stock, at average cost	14		16
Materials and supplies, at average cost	120		63
Prepaid income taxes	192		45
Other current assets	31		30
Total current assets	1,577		1,108
Property, Plant, and Equipment:
In service	8,348		7,275
Less accumulated provision for depreciation	1,374		1,248
Plant in service, net of depreciation	6,974		6,027
Construction work in progress	1,852		1,137
Total property, plant, and equipment	8,826		7,164
Other Property and Investments:
Goodwill	2		2
Other intangible assets, net of amortization of $14 and $12 at June 30, 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	165		166
Other deferred charges and assets — affiliated	23		9
Other deferred charges and assets — non-affiliated	173		139
Total deferred charges and other assets	361		314
Total Assets	$	11,082	$	8,905

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

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CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholders' Equity	At June 30, 2016			At December 31, 2015
	(in millions)
Current Liabilities:
Securities due within one year	$	403		$	403
Notes payable	831			137
Accounts payable —
Affiliated	80			66
Other	175			327
Accrued taxes —
Accrued income taxes	9			198
Other accrued taxes	16			5
Accrued interest	22			23
Contingent consideration	23			36
Other current liabilities	69			44
Total current liabilities	1,628			1,239
Long-term Debt	3,929			2,719
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	524			601
Accumulated deferred investment tax credits	1,107			889
Accrued income taxes, non-current	109			109
Asset retirement obligations	28			21
Deferred capacity revenues — affiliated	7			17
Other deferred credits and liabilities	105			3
Total deferred credits and other liabilities	1,880			1,640
Total Liabilities	7,437			5,598
Redeemable Noncontrolling Interests	47			43
Common Stockholder's Equity:
Common stock, par value $.01 per share —
Authorized — 1,000,000 shares
Outstanding — 1,000 shares	—			—
Paid-in capital	2,121			1,822
Retained earnings	661			657
Accumulated other comprehensive income (loss)	(6		)	4
Total common stockholder's equity	2,776			2,483
Noncontrolling interests	822			781
Total stockholders' equity	3,598			3,264
Total Liabilities and Stockholders' Equity	$	11,082		$	8,905

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

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SECOND QUARTER 2016 vs. SECOND QUARTER 2015

AND

YEAR-TO-DATE 2016 vs. YEAR-TO-DATE 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 with investor-owned utilities, independent power producers, municipalities, electric cooperatives, and other load-serving entities. In general, Southern Power has constructed or acquired new generating capacity only after entering into or assuming long-term PPAs for the new facilities.

During the six months ended June 30, 2016, Southern Power acquired or commenced construction of approximately 333 MWs of additional solar and wind facilities and committed to acquire approximately 656 MWs of solar and wind facilities. Subsequent to June 30, 2016, Southern Power acquired or commenced construction of approximately 278 MWs of solar facilities. See FUTURE EARNINGS POTENTIAL – "Acquisitions" and "Construction Projects" herein for additional information.

At June 30, 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 17 years. These ratios include the PPAs and capacity associated with 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

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$43	93.5	$60	75.9

Net income attributable to Southern Power for the second quarter 2016 was $89 million compared to $46 million for the corresponding period in 2015. Net income attributable to Southern Power for year-to-date 2016 was $139 million compared to $79 million for the corresponding period in 2015. The increases were primarily due to increased federal income tax benefits from solar ITCs and wind PTCs and increased renewable energy sales, partially offset by increases in depreciation and operations and maintenance expenses all related to new solar and wind facilities placed in service.

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Operating Revenues

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$36	10.7	$4	0.6

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 Southern Power's 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.

	Second Quarter 2016 vs. Second Quarter 2015				Year-to-Date 2016 vs. Year-to-Date 2015
	(change in millions)			(% change)	(change in millions)			(% change)
PPA capacity revenues	$	(2	)	(1.8)	$	(5	)	(1.9)
PPA energy revenues	17			11.6	18			6.7
Total PPA revenues	15			5.2	13			2.5
Revenues not covered by PPA	21			43.7	(9		)	(6.2)
Total operating revenues	$	36		10.7%	$	4		0.6%

In the second quarter 2016, operating revenues were $373 million compared to $337 million for the corresponding period in 2015. The $36 million increase in operating revenues was primarily due to the following:

• PPA capacity revenues decreased $2 million as a result of a $10 million decrease in non-affiliate capacity revenues, partially offset by an $8 million increase in affiliate capacity revenues primarily due to the remarketing of generation capacity.

• PPA energy revenuesincreased $17 million primarily due to a $37 million increase in renewable energy sales, arising from new solar and wind facilities, partially offset by a decrease of $20 million in fuel revenues related to natural gas facility PPAs.

• Revenues not covered by PPA increased $21 million due to a $15 million increase related to short-term sales to non-affiliates and a $6 million increase primarily due to a 30% increase in KWH sales to the power pool driven by lower natural gas prices.

For year-to-date 2016, operating revenues were $688 million compared to $684 million for the corresponding period in 2015. The $4 million increase in operating revenues was primarily due to the following:

• PPA capacity revenues decreased $5 million as a result of a $26 million decrease in non-affiliate capacity revenues, partially offset by a $21 million increase in affiliate capacity revenues primarily due to the remarketing of generation capacity.

• PPA energy revenuesincreased $18 million primarily due to a $58 million increase in renewable energy sales arising from new solar and wind facilities, partially offset by a decrease of $40 million in fuel revenues related to natural gas facility PPAs.

• Revenues not covered by PPA decreased $9 million due to a $25 million decrease primarily related to a 21% decrease in volume of sales into the power pool associated with increased scheduled outages and a reduction in demand driven by milder weather, partially offset by lower natural gas prices. The decrease was partially offset by a $16 million increase related to short-term sales to non-affiliates.

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.

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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. 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.

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:

	Second Quarter 2016	Second Quarter 2015	Year-to-Date 2016	Year-to-Date 2015
Generation (in billions of KWHs)	9.1	7.5	16.7	15.4
Purchased power (in billions of KWHs)	0.9	0.5	1.5	0.9
Total generation and purchased power	10.0	8.0	18.2	16.3
Total generation and purchased power excluding solar, wind, and tolling agreements	5.7	4.8	11.0	10.7

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.

	Second Quarter 2016 vs. Second Quarter 2015				Year-to-Date 2016 vs. Year-to-Date 2015
	(change in millions)			(% change)	(change in millions)			(% change)
Fuel	$	(9	)	(8.6)	$	(56	)	(23.0)
Purchased power	1			4.5	(5		)	(10.4)
Total fuel and purchased power expenses	$	(8	)		$	(61	)

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In the second quarter 2016, total fuel and purchased power expenses were $119 million compared to $127 million for the corresponding period in 2015. The decrease was primarily due to the following:

• Fuel expense decreased $9 million primarily due to a $22 million decrease associated with the average cost of natural gas per KWH generated, partially offset by a $13 million increase associated with the volume of KWHs generated.

• Purchased power expense increased $1 million due to a $13 million increase associated with the volume of KWHs purchased, largely offset by an $8 million decrease in the average cost of purchased power and a $4 million decrease associated with a PPA expiration.

For year-to-date 2016, total fuel and purchased power expenses were $230 million compared to $291 million for the corresponding period in 2015. The decrease was primarily due to the following:

• Fuel expense decreased $56 million primarily due to a $51 million decrease associated with the average cost of natural gas per KWH generated and a $5 million decrease associated with the volume of KWHs generated.

• Purchased power expense decreased $5 million due to a $21 million decrease in the average cost of purchased power and an $8 million decrease associated with a PPA expiration, largely offset by a $24 million increase associated with the volume of KWHs purchased.

Other Operations and Maintenance Expenses

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$17	24.6	$41	33.9

In the second quarter 2016, other operations and maintenance expenses were $86 million compared to $69 million for the corresponding period in 2015. The increase was primarily due to an $8 million increase in expenses associated with new solar and wind facilities placed in service in 2015 and 2016, a $5 million increase in general business expenses associated with Southern Power's overall growth strategy, and a $4 million increase associated with scheduled outage and maintenance expenses.

For year-to-date 2016, other operations and maintenance expenses were $162 million compared to $121 million for the corresponding period in 2015. The increase was primarily due to an $18 million increase associated with scheduled outage and maintenance expenses, a $13 million increase in expenses associated with new solar and wind facilities placed in service in 2015 and 2016, and a $10 million increase in general business expenses associated with Southern Power's overall growth strategy.

Depreciation and Amortization

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$21	35.0	$36	30.5

In the second quarter 2016, depreciation and amortization was $81 million compared to $60 million for the corresponding period in 2015. For year-to-date 2016, depreciation and amortization was $154 million compared to $118 million for the corresponding period in 2015. The increases were primarily due to additional depreciation related to new solar and wind facilities placed in service in 2015 and 2016.

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Interest Expense, net of Amounts Capitalized

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$(1)	(4.3)	$(2)	(4.4)

In the second quarter 2016, interest expense, net of amounts capitalized was $22 million compared to $23 million for the corresponding period in 2015. The decrease was primarily due to an $11 million increase in capitalized interest associated with the construction of solar facilities, largely offset by an increase of $10 million in interest expense related to additional debt issued in November 2015 and June 2016 primarily to fund Southern Power's growth strategy and continuous construction program.

For year-to-date 2016, interest expense, net of amounts capitalized was $43 million compared to $45 million for the corresponding period in 2015. The decrease was primarily due to a $20 million increase in capitalized interest associated with the construction of solar facilities, largely offset by an increase of $18 million in interest expense related to additional debt issued in November 2015 and June 2016 primarily to fund Southern Power's growth strategy and continuous construction program.

Income Taxes (Benefit)

Second Quarter 2016 vs. Second Quarter 2015		Year-to-Date 2016 vs. Year-to-Date 2015
(change in millions)	(% change)	(change in millions)	(% change)
$(42)	N/M	$(78)	N/M

N/M - Not meaningful

In the second quarter 2016, income tax benefit was $(41) million compared to an expense of $1 million for the corresponding period in 2015. The change was primarily due to a $46 million increase in federal income tax benefits from solar ITCs and wind PTCs in 2016, partially offset by a $4 million increase in tax expense related to beneficial state apportionment rate changes in 2015.

For year-to-date 2016, income tax benefit was $(65) million compared to an expense of $13 million for the corresponding period in 2015. The change was primarily due to a $75 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, partially offset by a $4 million increase in tax expense related to beneficial state apportionment rate changes in 2015.

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 and PTCs. 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. Generally, under the solar and wind generation PPAs, the purchasing party retains the right to keep or resell the renewable energy credits.

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 coverage 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 June 30, 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 17 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 discussed below. 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.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Project Facility	Resource	Approx. Nameplate Capacity	Location	Percentage Ownership	Expected/Actual COD	PPA Contract Period
		(MW)
Acquisitions During the Six Months Ended June 30, 2016
Calipatria	Solar	20	Imperial County, CA	90%	February 2016	20 years
East Pecos	Solar	120	Pecos County, TX	100%	Fourth quarter 2016	15 years
Grant Wind	Wind	151	Grant County, OK	100%	April 2016	20 years
Passadumkeag	Wind	42	Penobscot County, ME	100%	July 2016	15 years
Acquisitions Subsequent to June 30, 2016
Henrietta	Solar	102	Kings County, CA	51%(*)	July 2016	20 years
Lamesa	Solar	102	Dawson County, TX	100%	Second quarter 2017	15 years
Rutherford	Solar	74	Rutherford County, NC	90%	Fourth quarter 2016	15 years

(*) 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. In addition, Southern Power is entitled to substantially all of the federal tax benefits with respect to the transaction.

Acquisitions During the Six Months Ended June 30, 2016

Total construction costs, excluding the acquisition costs, are expected to be approximately $160 million to $180 million for East Pecos, which is currently under construction. The ultimate outcome of this matter cannot be determined at this time.

Acquisitions Subsequent to June 30, 2016

Total aggregate construction costs, excluding the acquisition costs, are expected to be approximately $260 million to $300 million for Lamesa and Rutherford, which are currently under construction. The ultimate outcome of these matters cannot be determined at this time.

Acquisition Agreements Executed but Not Yet Closed

During the six months ended June 30, 2016 and subsequent to that date, Southern Power entered into agreements to acquire the following projects for an aggregate purchase price of $1.1 billion: 100% ownership interests in two wind facilities totaling 299 MWs in Texas, significantly covered with PPAs for the first 12 to 14 years of operation; a 51% ownership interest (through 100% ownership of the Class A membership interests entitling Southern Power to 51% of all cash distributions and significantly all of the federal tax benefits) in a 100-MW solar facility in Nevada with a 20-year PPA; and a 90.1% ownership interest in a 257-MW wind facility in Texas significantly covered with a 12-year PPA. These acquisitions are expected to close in the third and fourth quarters of 2016. The ultimate outcome of these matters cannot be determined at this time.

The aggregate amount of revenue recognized by Southern Power related to the project facilities acquired during the six months ended June 30, 2016 included in the consolidated statement of income for year-to-date 2016 is $4 million. The aggregate amount of net income, excluding impacts of ITCs and PTCs, attributable to Southern Power related to the project facilities acquired during the six months ended June 30, 2016 included in the consolidated statement of income is immaterial. These businesses did not have operating revenues or activities prior to completion of construction and their assets being placed in service; therefore, supplemental pro forma information as though the acquisitions occurred as of the beginning of 2016 and for the comparable 2015 period is not meaningful and has been omitted.

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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 six months ended June 30, 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 June 30, 2016, total costs of construction incurred for the projects below were $2.7 billion, of which $1.7 billion remains in CWIP. Including the total construction costs incurred to date and the acquisition prices allocated to CWIP, total aggregate construction costs for the projects below are estimated to be approximately $3.0 billion to $3.2 billion. The ultimate outcome of these matters cannot be determined at this time.

Solar Facility	Approx. Nameplate Capacity	Location	Expected/Actual COD	PPA Contract Period
	(MW)
Butler	103	Taylor County, GA	Fourth quarter 2016	30 years
Desert Stateline(a)	299(b)	San Bernardino County, CA	Through third quarter 2016	20 years
Garland and Garland A	205	Kern County, CA	Fourth quarter 2016 and Third quarter 2016	15 years and 20 years
Roserock	160	Pecos County, TX	Fourth quarter 2016	20 years
Sandhills	146	Taylor County, GA	Fourth quarter 2016	25 years
Tranquillity	205	Fresno County, CA	July 2016	18 years

(a) 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.

(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 152 MWs were placed in service during the six months ended June 30, 2016. Subsequent to June 30, 2016, 37 MWs were placed in service.

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

Other Matters

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

TheultimateoutcomeofsuchpendingorpotentiallitigationagainstSouthern Powercannotbepredictedatthistime;however,forcurrentproceedingsnotspecificallyreportedinNote(B)totheCondensedFinancialStatementshereinorinNote3tothefinancialstatementsofSouthern PowerinItem8ofthe 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.

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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 June 30, 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 provided from operating activities totaled $51 million for the first six months of 2016, compared to $251 million for the first six months of 2015. The decrease in cash provided from operating activities was primarily due to an increase in income taxes paid. Net cash used for investing activities totaled $2.0 billion for the first six months of 2016 primarily due to acquisitions and the construction of renewable facilities. Net cash provided from financing activities totaled $2.1 billion for the first six months of 2016 primarily due to an increase in senior notes and notes payable. Cash flows 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 six months of 2016 include a $715 million increase in CWIP due to the acquisition and continued construction of new solar and wind facilities and a $947 million increase in plant in service, primarily due to solar and wind facilities being placed in service. Other significant changes include a $192 million increase in cash and cash equivalents and a $1.9 billion increase in notes payable and long-term debt primarily due to additional borrowings to fund acquisitions and construction projects. 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 June 30, 2017. In addition, during the six months ended

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June 30, 2016, Southern Power entered into new long-term service agreements (LTSA), which begin in 2020 and result in additional future commitments totaling approximately $784 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. Capital expenditures of Southern Power are currently estimated to total approximately $4.5 billion for 2016, which includes approximately $4.4 billion for acquisitions and/or construction of new generating facilities. Capital expenditures of Southern Power are currently estimated to total approximately $1.0 billion and $1.5 billion for 2017 and 2018, respectively. 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 acquisitions, 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 June 30, 2016, Southern Power's current liabilities exceeded current assets by $51 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 fluctuations in cash needs, due to both seasonality and the stage of 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 June 30, 2016, Southern Power had cash and cash equivalents of approximately $1.0 billion.

Details of short-term borrowings were as follows:

	Short-term Debt at June 30, 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	$	62	0.8	%	$	194	0.8	%	$	310

(*) Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 2016.

Company Facility

At June 30, 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.

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

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 June 30, 2016.

Project	Maturity Date	Construction Loan Facility		Bridge Loan Facility		Loan Facility Total		Total Loan Facility Undrawn		Letter of Credit Facility		Total Letter of Credit Facility Undrawn
		(in millions)
Tranquillity	Earlier of PPA COD or December 31, 2016	$	86	$	172	$	258	$	19	$	77	$	26
Roserock	Earlier of PPA COD or November 30, 2016	63		180		243		34		23		16
Garland	Earlier of PPA COD or November 30, 2016	86		308		394		73		49		23
Total		$	235	$	660	$	895	$	126	$	149	$	65

The Project Credit Facilities had total amounts outstanding as of June 30, 2016 of $769 million at a weighted average interest rate of 2.02%. For the three-month period ended June 30, 2016, these credit agreements had a maximum amount outstanding of $769 million and an average amount outstanding of $586 million at a weighted average interest rate of 2.03%.

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.

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.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 June 30, 2016 were as follows:

Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB and/or Baa2	$	29
At BBB- and/or Baa3	$	377
Below BBB- and/or Baa3	$	1,086

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 six months ended June 30, 2016, Southern Power's subsidiaries borrowed an additional $632 million pursuant to the Project Credit Facilities at a weighted average interest rate of 2.00%. In addition, Southern Power's subsidiaries issued $16 million in letters of credit. Subsequent to June 30, 2016, Southern Power's subsidiaries borrowed $48 million pursuant to the Project Credit Facilities at a weighted average interest rate of 1.98%.

In June 2016, Southern Power issued €600 million aggregate principal amount of Series 2016A 1.00% Senior Notes due June 20, 2022 and €500 million aggregate principal amount of Series 2016B 1.85% Senior Notes due June 20, 2026. The proceeds will be allocated to renewable energy generation projects. Southern Power's obligations under its euro-denominated fixed-rate notes were effectively converted to fixed-rate U.S. dollars at issuance through cross-currency swaps, removing foreign currency exchange risk associated with the interest and principal payments. See Note (H) to the Condensed Financial Statements under "Foreign Currency Derivatives" herein for additional information.

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.

138

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	140
B	Contingencies and Regulatory Matters	142
C	Fair Value Measurements	158
D	Stockholders' Equity	162
E	Financing	164
F	Retirement Benefits	167
G	Income Taxes	170
H	Derivatives	172
I	Acquisitions	185
J	Segment and Related Information	191

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

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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 June 30, 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 unchanged and 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 electric 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 electric operating companies currently recognize any excess tax benefits and deficiencies related to the exercise and vesting of stock compensation in additional paid-in capital. ASU 2016-09 is effective for fiscal years beginning after December 15, 2016. Early adoption is permitted and Southern Company and the traditional

140

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

electric operating companies intend to adopt the ASU in the fourth quarter 2016. The adoption is not expected to have a material impact on the results of operations, financial position, or cash flows of Southern Company and the traditional electric operating companies.

Affiliate Transactions

In 2014, prior to Southern Company's acquisition of PowerSecure International, Inc. (PowerSecure) on May 9, 2016, Georgia Power entered into two agreements with PowerSecure to build solar power generation facilities at two U.S. Army bases, as approved by the Georgia PSC. Payments of approximately $102 million made by Georgia Power to PowerSecure under the two agreements since inception in 2014 are included in CWIP at June 30, 2016. PowerSecure construction service costs of approximately $13 million are included in accounts payable, affiliated in Georgia Power's balance sheet at June 30, 2016. The facilities will be owned and operated by Georgia Power and are expected to be operational by the end of 2016. The ultimate outcome of this matter cannot be determined at this time.

See Note (I) under "Southern Company– Acquisition of PowerSecure International, Inc." for additional information regarding Southern Company's acquisition of PowerSecure.

Asset Retirement Obligations

See Note 1 to the financial statements of Southern Company, Alabama Power, Georgia Power, Gulf Power, and Mississippi Power under "Asset Retirement Obligations and Other Costs of Removal" in Item 8 of the Form 10-K for additional information regarding the EPA's regulation of CCR.

The cost estimates below are based on information as of June 30, 2016 using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the Disposal of Coal Combustion Residuals from Electric Utilities final rule requirements for closure in place or by other methods. As further analysis is performed, including evaluation of the expected method of compliance, refinement of assumptions underlying the cost estimates, such as the quantities of CCR at each site, and the determination of timing, including the potential for closing ash ponds prior to the end of their currently anticipated useful life, the traditional electric operating companies expect to continue to periodically update these estimates.

As of June 30, 2016, details of the asset retirement obligations (ARO) included in the registrants' Condensed Balance Sheets were as follows:

	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power			Southern Power
	(in millions)
Balance at beginning of year	$	3,759		$	1,448		$	1,916		$	130		$	177		$	21
Liabilities incurred	9			5			—			—			—			4
Liabilities settled	(66		)	(6		)	(52		)	(1		)	(7		)	—
Accretion	77			36			34			1			2			1
Cash flow revisions	699			19			673			3			6			2
Balance at end of period	$	4,478		$	1,502		$	2,571		$	133		$	178		$	28

The traditional electric operating companies' increases in cash flow revisions for the six months ended June 30, 2016 primarily relate to changes in ash pond closure strategy. The increase for Georgia Power was due to its decision in June 2016 to cease operating and stop receiving coal ash at all of its ash ponds within the next three years and to eventually close all of its ash ponds either by removal, consolidation, and/or recycling for the beneficial use of coal ash or through closure in place using advanced engineering methods.

141

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Goodwill and Other Intangible Assets

Goodwill and other intangible assets consisted of the following:

	At June 30, 2016
	Estimated Useful Life	Gross Carrying Amount		Accumulated Amortization			Intangible Assets, Net
		(in millions)
Intangibles subject to amortization:
Southern Company
Customer relationships	14-26 years	$	47	$	—		$	47
Trade names	5-9 years	43		—			43
Patents	3-10 years	4		—			4
Backlog	5 years	5		—			5
Southern Power
PPA fair value adjustments	20 years	330		(14		)	316
Total intangibles subject to amortization		$	429	$	(14	)	$	415
Intangibles not subject to amortization:
Southern Company
Federal Communications Commission licenses		$	75	$	—		$	75
Goodwill:
Southern Company		$	262	$	—		$	262
Southern Power		2		—			2
Total goodwill and other intangible assets		$	768	$	(14	)	$	754

Amortization expense associated with intangible assets during the three and six months ended June 30, 2016 was immaterial.

Intangibles at December 31, 2015 consisted primarily of Southern Power's PPA fair value adjustments with a net carrying amount of $317 million. The increases in goodwill and other intangibles relate to Southern Company's acquisition of PowerSecure on May 9, 2016.

See Note 12 to the financial statements of Southern Company under "Southern Power" and Note 2 to the financial statements of Southern Power in Item 8 of the Form 10-K for additional information regarding Southern Power's PPA fair value adjustments. See Note (I) under "Southern Company– Acquisition of PowerSecure International, Inc." for additional information regarding Southern Company's acquisition of PowerSecure.

(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

142

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

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 electric 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 June 30, 2016 was $23 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. On July 29, 2016, Honeywell International, Inc. and Georgia Power entered into a consent decree with the EPA to perform additional remediation at the site. Additional response actions at the 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, including costs associated with implementation of the consent decree. 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 June 30, 2016. These estimated costs primarily relate to site closure criteria by the Florida Department of Environmental Protection (FDEP) for potential impacts to soil and groundwater from herbicide applications at Gulf Power substations. The schedule for completion of the remediation projects is subject to FDEP approval. The projects have been approved by the Florida PSC for recovery through Gulf Power's environmental cost recovery clause; therefore, these liabilities have no impact on net income.

The final outcome of these matters cannot be determined at this time. However, based on the currently known conditions at these sites and the nature and extent of activities relating to these sites, management of Southern Company and Gulf Power does not believe that additional liabilities, if any, at these sites would be material to their respective financial statements.

FERC Matters

Municipal and Rural Associations Tariff

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

143

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

On March 31, 2016, Mississippi Power reached a settlement agreement with its wholesale customers and filed a request with the FERC for an increase in wholesale base revenues under the Municipal and Rural Associations (MRA) cost-based electric tariff. The settlement agreement, accepted by the FERC, effective for services rendered beginning May 1, 2016, provides that base rates under the MRA cost-based electric tariff will produce additional annual base revenues of $7 million. 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 to similar regulatory treatment for MRA tariff ratemaking as the treatment approved for retail ratemaking under the December 2015 Mississippi PSC order authorizing rates providing recovery of assets previously placed in service (In-Service Asset Rate Order). This regulatory treatment primarily includes (i) recovery of the Kemper IGCC assets currently operational and providing service to customers and other related costs, (ii) amortization of the Kemper IGCC-related regulatory assets included in rates under the settlement agreement over 36 months, (iii) Kemper IGCC-related expenses included in rates under the settlement agreement no longer being deferred and charged to expense, and (iv) removing all of the Kemper IGCC CWIP from rate base with a corresponding increase in accrual of AFUDC. The additional resulting AFUDC is estimated to be approximately $8 million through the Kemper IGCC's projected in-service date of October 31, 2016.

Fuel Cost Recovery

Mississippi Power has a wholesale MRA and a Market Based (MB) fuel cost recovery factor. At June 30, 2016, the amount of over-recovered wholesale MRA fuel costs included in the balance sheets was $23 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 electric 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 electric 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 electric 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 electric operating companies and in some adjacent areas. The FERC directed the traditional electric 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 electric 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.

144

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	June 30, 2016		December 31, 2015
		(in millions)
Rate CNP Compliance	Under recovered regulatory clause revenues	$	7	$	43
	Deferred under recovered regulatory clause revenues	21		—
Rate CNP PPA	Deferred under recovered regulatory clause revenues	115		99
Retail Energy Cost Recovery	Other regulatory liabilities, current	75		238
	Deferred over recovered regulatory clause revenues	102		—
Natural Disaster Reserve	Other regulatory liabilities, deferred	72		75

Environmental Accounting Order

In April 2016, as part of its environmental compliance strategy, Alabama Power ceased using coal at Plant Greene County Units 1 and 2 (300 MWs representing Alabama Power's ownership interest) and began operating Units 1 and 2 solely on natural gas in May 2016 and July 2016, respectively.

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" herein 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 acquisition of Southern Company Gas 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) each will retain their respective merger savings, net of transition costs, as defined in the settlement agreement; through December 31, 2022, such net merger savings applicable to each utility will be shared on a 60/40 basis between their respective customers and the Utilities; thereafter, all merger savings will be retained by customers. See Note (I) under "Southern Company – Merger with Southern Company Gas" for additional information regarding the Merger.

145

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Integrated Resource Plan

See Note 3 to the financial statements of Southern Company and Georgia Power under "Retail Regulatory Matters – Georgia Power – Integrated Resource Plan" and "Retail Regulatory Matters – Integrated Resource Plan," respectively, in Item 8 of the Form 10-K for additional information regarding Georgia Power's triennial Integrated Resource Plan (2016 IRP).

On July 28, 2016, the Georgia PSC voted to approve the 2016 IRP including the decertification and retirement of Plant Mitchell Units 3, 4A, and 4B (217 MWs) and Plant Kraft Unit 1 combustion turbine (17 MWs), as well as the decertification of the Intercession City unit (143 MWs total capacity). On August 2, 2016, the Plant Mitchell and Plant Kraft units were retired. Georgia Power exercised its contractual option to sell its 33% ownership interest in the Intercession City unit to Duke Energy Florida, Inc., with an expected closing date in late August 2016.

Additionally, the Georgia PSC approved Georgia Power's environmental compliance strategy and related expenditures proposed in the 2016 IRP, including measures taken to comply with existing government-imposed environmental mandates, subject to limits on expenditures for Plant McIntosh Unit 1 and Plant Hammond Units 1 through 4.

The Georgia PSC approved reclassification of the remaining net book value of Plant Mitchell Unit 3 and costs associated with materials and supplies remaining at the unit retirement date to a regulatory asset. Recovery of the unit's net book value will continue through December 31, 2019, as provided in the 2013 ARP. Recovery of the remaining balance of the unit's net book value as of December 31, 2019 and costs associated with materials and supplies remaining at the unit retirement date will be deferred for consideration in Georgia Power's 2019 general base rate case.

The Georgia PSC also approved the Renewable Energy Development Initiative to procure an additional 1,200 MWs of renewable resources primarily utilizing market-based prices established through a competitive bidding process with expected in-service dates between 2018 and 2021. Additionally, 200 MWs of self-build capacity for use by Georgia Power was approved, as well as consideration for no more than 200 MWs of capacity as part of a renewable commercial and industrial program.

The Georgia PSC also approved recovery of costs up to $99 million through June 30, 2019 to preserve the nuclear option at a future generation site in Stewart County, Georgia. The timing of cost recovery will be determined by the Georgia PSC in a future base rate case. The ultimate outcome of this matter cannot be determined at this time.

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 June 30, 2016 and December 31, 2015, Georgia Power's over recovered fuel balance totaled $164 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. On May 17, 2016, the Georgia PSC approved Georgia Power's request to decrease fuel rates by 15% effective June 1, 2016, which will reduce annual billings by approximately $313 million. Georgia Power is currently scheduled to file its next fuel case by February 28, 2017.

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

146

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

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

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

The Vogtle Owners may terminate the Vogtle 3 and 4 Agreement at any time for their convenience, provided that the Vogtle Owners will be required to pay certain termination costs. The Contractor may terminate the Vogtle 3 and 4 Agreement under certain circumstances, including certain Vogtle Owner suspension or delays of work, action by a governmental authority to permanently stop work, certain breaches of the Vogtle 3 and 4 Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events.

In 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4. Georgia Power is required to file semi-annual VCM reports with the Georgia PSC by February 28 and August 31 each year. If the projected construction capital costs to be borne by Georgia Power increase by 5% above the certified cost or the projected in-service dates are significantly extended, Georgia Power is required to seek an amendment to the Plant Vogtle Units 3 and 4 certificate from the Georgia PSC. In February 2013, Georgia Power requested an amendment to the certificate to increase the estimated in-service capital cost of Plant Vogtle Units 3 and 4 from $4.4 billion to $4.8 billion and to extend the estimated in-service dates to the fourth quarter 2017 (from April 2016) and the fourth quarter 2018 (from April 2017) for Plant Vogtle Units 3 and 4, respectively. In October 2013, the Georgia PSC approved a stipulation (2013 Stipulation) between Georgia Power and the Georgia PSC Staff (Staff) to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate until the completion of Plant Vogtle Unit 3 or earlier if deemed appropriate by the Georgia PSC and Georgia Power.

On April 15, 2015, the Georgia PSC issued a procedural order in connection with the twelfth VCM report, which included a requested amendment (Requested Amendment) to the Plant Vogtle Units 3 and 4 certificate to reflect the Contractor's revised forecast for completion of Plant Vogtle Units 3 and 4 (second quarter of 2019 and second quarter of 2020, respectively) as well as additional estimated Vogtle Owner's costs, of approximately $10 million per month, including property taxes, oversight costs, compliance costs, and other operational readiness costs to include the estimated Vogtle Owner's costs associated with the proposed 18-month Contractor delay and to increase

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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 $250 million had been paid as of June 30, 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 is conducting 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 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,

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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 incurred approximately $141 million in total construction capital costs during the period of January 1, 2016 through June 30, 2016. Georgia Power's CWIP balance for Plant Vogtle Units 3 and 4 was $3.7 billion as of June 30, 2016. The 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, of which $1.1 billion had been incurred through June 30, 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 matters, including the timely resolution of Inspections, Tests, Analyses, and Acceptance Criteria and the related approvals by the NRC, 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 labor productivity, fabrication, assembly, delivery, and installation of plant equipment, 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 that authorized Gulf Power to reduce depreciation and record a regulatory asset up to $62.5 million from January 2014 through 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 six months of 2016, Gulf Power recognized reductions in depreciation of $8.4 million, $20.1 million, and $6.4 million, respectively.

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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	June 30, 2016		December 31, 2015
		(in millions)
Fuel Cost Recovery	Other regulatory liabilities, current	$	18	$	18
Purchased Power Capacity Recovery	Under recovered regulatory clause revenues	4		1
Environmental Cost Recovery	Under recovered regulatory clause revenues	1		19
Energy Conservation Cost Recovery	Other regulatory liabilities, current	—		4

Mississippi Power

Energy Efficiency

See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Energy Efficiency" in Item 8 of the Form 10-K for additional information regarding Mississippi Power's energy efficiency programs.

On May 3, 2016, the Mississippi PSC issued an order approving the annual Energy Efficiency Cost Rider Compliance filing, which included an anticipated reduction of $2 million in retail revenues for the year ending December 31, 2016.

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.

On July 12, 2016, Mississippi Power submitted its annual projected PEP filing for 2016 which indicated no change in rates.

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

Fuel Cost Recovery

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

At June 30, 2016, the amount of over-recovered retail fuel costs included on Mississippi Power's Condensed Balance Sheet was $76 million compared to $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.

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

Kemper IGCC Schedule and Cost Estimate

In 2012, the Mississippi PSC issued the 2012 MPSC CPCN Order, a detailed order confirming the CPCN originally approved by the Mississippi PSC in 2010 authorizing the acquisition, construction, and operation of the Kemper IGCC. The certificated cost estimate of the Kemper IGCC included in the 2012 MPSC CPCN Order was $2.4 billion, net of $245 million of grants awarded to the Kemper IGCC project by the DOE under the Clean Coal Power Initiative Round 2 (Initial DOE Grants) and excluding the cost of the lignite mine and equipment, the cost of the CO₂ pipeline facilities, and AFUDC related to the Kemper IGCC. The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, with recovery of prudently-incurred costs subject to approval by the Mississippi PSC. The Kemper IGCC was originally projected to be placed in service in May 2014. Mississippi Power placed the combined cycle and the associated common facilities portion of the Kemper IGCC in service in August 2014 and continues to progress towards completing the remainder of the Kemper IGCC, including the gasifiers and the gas clean-up facilities. The in-service date for the remainder of the Kemper IGCC is currently expected to occur by October 31, 2016, which reflects a one-month extension. The initial production of syngas began on July 14, 2016 and testing has continued on gasifier 'B' and the related lignite feed and ash systems. The schedule extension provides for time to complete mechanical equipment modifications to the gasifiers' supporting systems to increase capacity to the levels necessary to complete the remaining start-up activities and achieve sustained operations on both gasifiers. The remaining schedule also reflects the time expected to complete the initial operation and testing of the facility's syngas clean-up systems, as well as the integration of all systems necessary for both combustion turbines to simultaneously generate electricity with syngas.

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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 June 30, 2016, are as follows:

Cost Category	2010 Project Estimate(a)		Current Cost Estimate(b)			Actual Costs
	(in billions)
Plant Subject to Cost Cap(c)(e)	$	2.40	$	5.43		$	5.15
Lignite Mine and Equipment	0.21		0.23			0.23
CO2 Pipeline Facilities	0.14		0.11			0.12
AFUDC(d)	0.17		0.72			0.66
Combined Cycle and Related Assets Placed in Service – Incremental(e)	—		0.03			0.02
General Exceptions	0.05		0.10			0.09
Deferred Costs(e)	—		0.20			0.19
Additional DOE Grants(f)	—		(0.14		)	(0.14		)
Total Kemper IGCC	$	2.97	$	6.68		$	6.32

(a) 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, as well as the lignite mine and equipment, AFUDC, and general exceptions.

(b) Amounts in the Current Cost Estimate reflect estimated costs through October 31, 2016.

(c) 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 (e) for additional information.

(d) Mississippi Power's 2010 Project Estimate included recovery of financing costs during construction rather than the accrual of AFUDC. This approach was not approved by the Mississippi PSC as described in "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order." The Current Cost Estimate also 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.

(e) Non-capital Kemper IGCC-related costs incurred during construction were initially deferred as regulatory assets. Some of these costs are now included in rates and are being recognized through income; however such costs continue to be included in the Current Cost Estimate and the Actual Costs at June 30, 2016. The wholesale portion of debt carrying costs, whether deferred or recognized through income, are not included in the Current Cost Estimate and the Actual Costs at June 30, 2016. See "Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities" herein for additional information.

(f) 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.

Of the total costs, including post-in-service costs for the lignite mine, incurred as of June 30, 2016, $3.59 billion was included in property, plant, and equipment (which is net of the Initial DOE Grants, the Additional DOE Grants, and estimated probable losses of $2.55 billion), $6 million in other property and investments, $81 million in fossil fuel stock, $46 million in materials and supplies, $35 million in other regulatory assets, current, $180 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.

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Mississippi Power recorded pre-tax charges to income for revisions to the cost estimate of $81 million ($50 million after tax) in the second quarter 2016 and a total of $134 million ($83 million after tax) for the six months ended June 30, 2016. Since 2012, in the aggregate, Mississippi Power has incurred charges of $2.55 billion ($1.57 billion after tax) as a result of changes in the cost estimate above the cost cap for the Kemper IGCC through June 30, 2016. The increase to the cost estimate in 2016 primarily reflects costs for the extension of the Kemper IGCC's projected in-service date through October 31, 2016 and increased efforts related to operational readiness and challenges in start-up and commissioning activities, which includes the cost of repairs and modifications associated with the lignite feed process and the refractory lining for the gasifiers. Any extension of the in-service date beyond October 31, 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 October 31, 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 $3 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. Significant testing activities, including those for coal feed and gasification systems, as well as the initial operation and testing of the facility's gas clean-up systems and production of clean syngas, and, ultimately the generation of electricity, remain in process. Further cost increases and/or extensions of the expected in-service date may result from factors including, but not limited to, difficulties integrating the systems required for sustained operations, major equipment failure, unforeseen engineering or design problems including any repairs and/or modifications to systems, and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by the Mississippi PSC). Any further changes in the estimated costs to complete construction and start-up of the Kemper IGCC subject to the $2.88 billion cost cap, net of the Initial DOE Grants and excluding the Cost Cap Exceptions, will be reflected in Southern Company's and Mississippi Power's statements of income and these changes could be material.

Rate Recovery of Kemper IGCC Costs

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

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

2012 MPSC CPCN Order

The 2012 MPSC CPCN Order included provisions relating to both Mississippi Power's recovery of financing costs during the course of construction of the Kemper IGCC and Mississippi Power's recovery of costs following the date the Kemper IGCC is placed in service. With respect to recovery of costs following the in-service date of the Kemper IGCC, the 2012 MPSC CPCN Order provided for the establishment of operational cost and revenue parameters based upon assumptions in Mississippi Power's petition for the CPCN. Mississippi Power expects the Mississippi PSC to apply operational parameters in connection with future proceedings related to the operation of the Kemper IGCC. To the extent the Mississippi PSC determines the Kemper IGCC does not meet the operational parameters

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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

On August 13, 2015, the Mississippi PSC approved Mississippi Power's request for interim rates, 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. The interim rates were designed to collect approximately $159 million annually and became effective with the first billing cycle in September 2015, subject to refund and certain other conditions.

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

With implementation of the new rates 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.

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On July 27, 2016, the Court dismissed Greenleaf CO₂ Solutions, LLC (Greenleaf) motion for reconsideration of its previous decision to dismiss Greenleaf's appeal of the In-Service Asset Rate Order.

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.

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 June 30, 2016 of $6.68 billion, Mississippi Power anticipates that it will incur additional expenses in excess of current rates associated with operating the Kemper IGCC after it is placed in service until the Kemper IGCC cost recovery approach is finalized, which are expected to be material. These costs include, but are not limited to, regulatory costs, operational costs in excess of current rates, and additional carrying costs. Mississippi Power will seek approval from the Mississippi PSC to defer these costs for future rate recovery to be determined in connection with the final Kemper IGCC cost recovery approach ultimately approved. See "Regulatory Assets and Liabilities" below for additional information.

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 and second quarter 2016, in connection with the implementation of retail and wholesale rates, respectively, Mississippi Power began expensing certain ongoing project costs and certain retail 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 and the settlement agreement with wholesale customers. As of June 30, 2016, the balance associated with these regulatory assets was $114 million, of which $35 million is included in current assets. Other regulatory assets associated with the remainder of the Kemper IGCC totaled $101 million as of June 30, 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. Also see "FERC Matters" herein for information related to the 2016 settlement agreement with wholesale customers.

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.

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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. At June 30, 2016, Mississippi Power's related regulatory liability included in its balance sheet totaled approximately $5 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 entered into agreements with Denbury Onshore (Denbury) and Treetop Midstream Services, LLC, pursuant to which Denbury would purchase 70% of the CO₂ captured from the Kemper IGCC and Treetop would purchase 30% of the CO₂ captured from the Kemper IGCC. On June 3, 2016, Mississippi Power cancelled its contract with Treetop and amended its contract with Denbury to reflect, among other things, Denbury's agreement to purchase 100% of the CO₂ captured from the Kemper IGCC, an initial contract term of 16 years, and termination rights if Mississippi Power has not satisfied its contractual obligation to deliver captured CO₂ by July 1, 2017, in addition to Denbury's existing termination rights in the event of a change in law, force majeure, or an event of default by Mississippi Power. Any termination or material modification of the agreement with Denbury could impact the operations of the Kemper IGCC and 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 or otherwise sequester the CO₂ produced. Additionally, 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.

Litigation

On April 26, 2016, a complaint against Mississippi Power was filed in Harrison County Circuit Court (Circuit Court) by Biloxi Freezing & Processing Inc., Gulfside Casino Partnership, and John Carlton Dean, which was amended and refiled on July 11, 2016 to include, among other things, Southern Company as a defendant. The individual plaintiff, John Carlton Dean, alleges that Mississippi Power and Southern Company violated the Mississippi Unfair Trade Practices Act. All plaintiffs have alleged that Mississippi Power and Southern Company concealed, falsely represented, and failed to fully disclose important facts concerning the cost and schedule of the Kemper IGCC and that these alleged breaches have unjustly enriched Mississippi Power and Southern Company. The plaintiffs seek unspecified actual damages and punitive damages; ask the Circuit Court to appoint a receiver to oversee, operate, manage, and otherwise control all affairs relating to the Kemper IGCC; ask the Circuit Court to revoke any licenses or certificates authorizing Mississippi Power or Southern Company to engage in any business related to the Kemper IGCC in Mississippi; and seek 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.

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On June 9, 2016, Treetop, Greenleaf, Tenrgys, LLC, Tellus Energy, LLC, WCOA, LLC, and Tellus Operating Group filed a complaint against Mississippi Power, Southern Company, and SCS in the state court in Gwinnett County, Georgia. The complaint relates to the cancelled CO₂ contract with Treetop and alleges fraudulent misrepresentation, fraudulent concealment, civil conspiracy, and breach of contract on the part of Mississippi Power, Southern Company, and SCS and seeks compensatory damages of $100 million, as well as unspecified punitive damages.

Southern Company and Mississippi Power believe these legal challenges have no merit; however, an adverse outcome in these proceedings 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. Southern Company and Mississippi Power will vigorously defend themselves in these matters, and the ultimate outcome of these matters cannot be determined at this time.

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(C) FAIR VALUE MEASUREMENTS

As of June 30, 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 June 30, 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	$	—	$	36	$	—	$	—	$	36
Interest rate derivatives	—		27		—		—		27
Nuclear decommissioning trusts(a)	642		917		—		18		1,577
Cash equivalents	1,014		—		—		—		1,014
Other investments	9		—		1		—		10
Total	$	1,665	$	980	$	1	$	18	$	2,664
Liabilities:
Energy-related derivatives	$	—	$	110	$	—	$	—	$	110
Interest rate derivatives	—		7		—		—		7
Foreign currency derivatives	—		38		—		—		38
Total	$	—	$	155	$	—	$	—	$	155
Alabama Power
Assets:
Energy-related derivatives	$	—	$	10	$	—	$	—	$	10
Nuclear decommissioning trusts(b)
Domestic equity	363		67		—		—		430
Foreign equity	46		47		—		—		93
U.S. Treasury and government agency securities	—		24		—		—		24
Corporate bonds	21		142		—		—		163
Mortgage and asset backed securities	—		22		—		—		22
Private Equity	—		—		—		18		18
Other	—		8		—		—		8
Cash equivalents	210		—		—		—		210
Total	$	640	$	320	$	—	$	18	$	978
Liabilities:
Energy-related derivatives	$	—	$	22	$	—	$	—	$	22

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(UNAUDITED)

	Fair Value Measurements Using
As of June 30, 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	$	—	$	15	$	—	$	—	$	15
Interest rate derivatives	—		14		—		—		14
Nuclear decommissioning trusts(b) (c)
Domestic equity	187		1		—		—		188
Foreign equity	—		116		—		—		116
U.S. Treasury and government agency securities	—		109		—		—		109
Municipal bonds	—		57		—		—		57
Corporate bonds	—		159		—		—		159
Mortgage and asset backed securities	—		159		—		—		159
Other	25		6		—		—		31
Cash equivalents	90		—		—		—		90
Total	$	302	$	636	$	—	$	—	$	938
Liabilities:
Energy-related derivatives	$	—	$	5	$	—	$	—	$	5
Gulf Power
Assets:
Energy-related derivatives	$	—	$	2	$	—	$	—	$	2
Cash equivalents	20		—		—		—		20
Total	$	20	$	2	$	—	$	—	$	22
Liabilities:
Energy-related derivatives	$	—	$	55	$	—	$	—	$	55
Interest rate derivatives	—		7		—		—		7
Total	$	—	$	62	$	—	$	—	$	62
Mississippi Power
Assets:
Energy-related derivatives	$	—	$	1	$	—	$	—	$	1
Cash equivalents	102		—		—		—		102
Total	$	102	$	1	$	—	$	—	$	103
Liabilities:
Energy-related derivatives	$	—	$	23	$	—	$	—	$	23

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(UNAUDITED)

	Fair Value Measurements Using
As of June 30, 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 Power
Assets:
Energy-related derivatives	$	—	$	8	$	—	$	—	$	8
Cash equivalents	449		—		—		—		449
Total	$	449	$	8	$	—	$	—	$	457
Liabilities:
Energy-related derivatives	$	—	$	5	$	—	$	—	$	5
Foreign currency derivatives	—		38		—		—		38
Total	$	—	$	43	$	—	$	—	$	43

(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 June 30, 2016, approximately $46 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. The fair value of the funds at Southern Company, including reinvested interest and dividends and excluding the funds' expenses, increased by $28 million and $48 million, respectively, for the three and six months ended June 30, 2016, and decreased by $1 million and increased by $31 million, respectively, for the three and six months ended June 30, 2015. Alabama Power recorded an increase in fair value of $29 million and $40 million, respectively, for the three and six months ended June 30, 2016 and $5 million and $19 million, respectively, for the three and six months ended June 30, 2015 as a change in regulatory liabilities related to its AROs. Georgia Power recorded a decrease in fair value of $1 million and an increase of $8 million, respectively, for the three and six months ended June 30, 2016 and a decrease in fair value of $6 million and an increase in fair value of $12 million, respectively, for the three and six months ended June 30, 2015 as a change in its regulatory asset related to its AROs.

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 fair value of cross-currency swaps reflect the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future foreign currency exchange rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk, and discount rates. The interest rate derivatives and cross-currency swaps are categorized as Level 2 under Fair Value Measurements as these inputs are based on observable

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(UNAUDITED)

data and valuations of similar instruments. See Note (H) for additional information on how these derivatives are used.

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

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

As of June 30, 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 June 30, 2016:	Fair Value		Unfunded Commitments		Redemption Frequency	Redemption Notice Period
	(in millions)
Southern Company	$	18	$	28	Not Applicable	Not Applicable
Alabama Power	$	18	$	28	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 June 30, 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	$	37,953	$	40,992
Alabama Power	$	7,090	$	7,940
Georgia Power	$	10,603	$	11,881
Gulf Power	$	1,182	$	1,275
Mississippi Power	$	2,983	$	2,967
Southern Power	$	4,332	$	4,523

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.

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(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 June 30, 2016	Three Months Ended June 30, 2015	Six Months Ended June 30, 2016	Six Months Ended June 30, 2015
	(in millions)
As reported shares	934	909	925	910
Effect of options and performance share award units	6	3	6	4
Diluted shares	940	912	931	914

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 andsix months ended June 30, 2016, respectively, and were 15 million and 1 million for the three and six months ended June 30, 2015, respectively.

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(UNAUDITED)

Changes in Stockholders' Equity

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

	Number of Common Shares			Common Stockholders' Equity			Preferred and Preference Stock of Subsidiaries						Total Stockholders' Equity
	Issued	Treasury								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	—	—		1,097			—			—			1,097
Other comprehensive income (loss)	—	—		(117		)	—			—			(117		)
Stock issued	27,297	2,599		1,383			—			—			1,383
Stock-based compensation	—	—		82			—			—			82
Cash dividends on common stock	—	—		(1,023		)	—			—			(1,023		)
Contributions from noncontrolling interests	—	—		—			—			169			169
Distributions to noncontrolling interests	—	—		—			—			(10		)	(10		)
Purchase of membership interests from noncontrolling interests	—	—		—			—			(129		)	(129		)
Net income attributable to noncontrolling interests	—	—		—			—			11			11
Other	—	(19	)	1			—			—			1
Balance at June 30, 2016	942,370	(772	)	$	22,015		$	609		$	822		$	23,446
Balance at December 31, 2014	908,502	(725	)	$	19,949		$	756		$	221		$	20,926
Consolidated net income attributable to Southern Company	—	—		1,138			—			—			1,138
Other comprehensive income (loss)	—	—		7			—			—			7
Stock issued	3,222	—		117			—			—			117
Stock-based compensation	—	—		66			—			—			66
Stock repurchased, at cost	—	(2,599	)	(115		)	—			—			(115		)
Cash dividends on common stock	—	—		(972		)	—			—			(972		)
Preference stock redemption	—	—		—			(150		)	—			(150		)
Contributions from noncontrolling interests	—	—		—			—			135			135
Distributions to noncontrolling interests	—	—		—			—			(5		)	(5		)
Net income attributable to noncontrolling interests	—	—		—			—			4			4
Other	—	25		(8		)	3			—			(5		)
Balance at June 30, 2015	911,724	(3,299	)	$	20,182		$	609		$	355		$	21,146

(*) Primarily related to Southern Power Company.

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(E) FINANCING

Bank Credit Arrangements

Bank credit arrangements provide liquidity support to the registrants' commercial paper borrowings and the traditional electric operating companies' pollution control revenue bonds. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of June 30, 2016 was approximately $1.9 billion (comprised of approximately $890 million at Alabama Power, $868 million at Georgia Power, $82 million at Gulf Power, and $40 million at Mississippi Power). In addition, at June 30, 2016, the traditional electric operating companies had approximately $320 million (comprised of approximately $87 million at Alabama Power, $212 million at Georgia Power, and $21 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 and "Financing Activities" herein for additional information.

The following table outlines the committed credit arrangements by company as of June 30, 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)				(in millions)
Southern Company(a)	$	—	$	—	$	1,000	$	1,250	$	2,250	$	2,250	$	—	$	—	$	—	$	—
Alabama Power	3		32		500		800		1,335		1,335		—		—		—		35
Georgia Power	—		—		—		1,750		1,750		1,732		—		—		—		—
Gulf Power	75		40		165		—		280		280		45		—		45		70
Mississippi Power	115		60		—		—		175		150		—		15		15		160
Southern Power Company(b)	—		—		—		600		600		560		—		—		—		—
Other	25		45		—		40		110		80		20		—		20		50
Total	$	218	$	177	$	1,665	$	4,440	$	6,500	$	6,387	$	65	$	15	$	80	$	315

(a) On May 24, 2016, the $8.1 billion Bridge Agreement to provide Merger financing, to the extent necessary, was terminated.

(b) Excluding its subsidiaries. See "Southern Power 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 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 June 30, 2016.

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(UNAUDITED)

Project	Maturity Date	Construction Loan Facility		Bridge Loan Facility		Loan Facility Total		Total Loan Facility Undrawn		Letter of Credit Facility		Total Letter of Credit Facility Undrawn
		(in millions)
Tranquillity	Earlier of PPA COD or December 31, 2016	$	86	$	172	$	258	$	19	$	77	$	26
Roserock	Earlier of PPA COD or November 30, 2016	63		180		243		34		23		16
Garland	Earlier of PPA COD or November 30, 2016	86		308		394		73		49		23
Total		$	235	$	660	$	895	$	126	$	149	$	65

The Project Credit Facilities had total amounts outstanding as of June 30, 2016 of $769 million at a weighted average interest rate of 2.02%. For the three-month period ended June 30, 2016, these credit agreements had a maximum amount outstanding of $769 million and an average amount outstanding of $586 million at a weighted average interest rate of 2.03%.

Financing Activities

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

Company	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(a)
	(in millions)
Southern Company	$	8,500	$	—	$	—	$	—		$	—
Alabama Power	400		200		—		45			—
Georgia Power	650		500		4		300			3
Gulf Power	—		125		—		—			—
Mississippi Power	—		—		—		1,100			651
Southern Power	1,241		—		—		2			4
Other	—		—		—		—			10
Elimination(b)	—		—		—		(200		)	(225		)
Total	$	10,791	$	825	$	4	$	1,247		$	443

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

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

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Southern Company

In May 2016, Southern Company issued the following series of senior notes for an aggregate principal amount of $8.5 billion:

• $0.5 billion of 1.55% Senior Notes due July 1, 2018;

• $1.0 billion of 1.85% Senior Notes due July 1, 2019;

• $1.5 billion of 2.35% Senior Notes due July 1, 2021;

• $1.25 billion of 2.95% Senior Notes due July 1, 2023;

• $1.75 billion of 3.25% Senior Notes due July 1, 2026;

• $0.5 billion of 4.25% Senior Notes due July 1, 2036; and

• $2.0 billion of 4.40% Senior Notes due July 1, 2046.

The net proceeds were used to fund a portion of the Merger and related transaction costs and for other general corporate purposes.

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.

In June 2016, Georgia Power made additional borrowings under the FFB Credit Facility in an aggregate principal amount of $300 million. The interest rate applicable to the $300 million principal amount is 2.571% for an interest period that extends to the final maturity date of February 20, 2044. The proceeds were used to reimburse Georgia Power for Eligible Project Costs relating to the construction of Plant Vogtle Units 3 and 4.

Gulf Power

In May 2016, Gulf Power redeemed $125 million aggregate principal amount of its Series 2011A 5.75% Senior Notes due June 1, 2051.

Also in May 2016, Gulf Power entered into an 11-month floating rate bank loan bearing interest based on one-month LIBOR. This short-term loan was for $100 million aggregate principal amount and the proceeds were used to repay existing indebtedness and for working capital and other general corporate purposes.

166

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

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 June 30, 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 June 27, 2016, Mississippi Power received a capital contribution from Southern Company of $225 million, the proceeds of which were used to repay to Southern Company a portion of the existing promissory note issued in November 2015. As of June 30, 2016, the amount of outstanding promissory notes to Southern Company totaled $551 million.

On March 8, 2016, Mississippi Power entered into an unsecured term loan agreement with a syndicate of financial institutions 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.

In June 2016, Mississippi Power renewed a $10 million short-term note, which matures on June 30, 2017, bearing interest based on three-month LIBOR.

Southern Power

During the six months ended June 30, 2016, Southern Power's subsidiaries borrowed an additional $632 million pursuant to the Project Credit Facilities at a weighted average interest rate of 2.00%. In addition, Southern Power's subsidiaries issued $16 million in letters of credit.

In June 2016, Southern Power issued €600 million aggregate principal amount of Series 2016A 1.00% Senior Notes due June 20, 2022 and €500 million aggregate principal amount of Series 2016B 1.85% Senior Notes due June 20, 2026. The proceeds will be allocated to renewable energy generation projects. Southern Power's obligations under its euro-denominated fixed-rate notes were effectively converted to fixed-rate U.S. dollars at issuance through cross-currency swaps, removing foreign currency exchange risk associated with the interest and principal payments. See Note (H) under "Foreign Currency Derivatives" for additional information.

(F) RETIREMENT BENEFITS

Southern Company has a defined benefit, trusteed, pension plan covering substantially all employees. The qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended. No mandatory contributions to the qualified pension plan are anticipated for the year ending December 31, 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 electric 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.

167

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Components of the net periodic benefit costs for the three and six months ended June 30, 2016 and 2015 were as follows:

Pension Plans	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power
	(in millions)
Three Months Ended June 30, 2016
Service cost	$	62		$	15		$	18		$	3		$	3
Interest cost	101			24			34			4			5
Expected return on plan assets	(187		)	(46		)	(65		)	(8		)	(8		)
Amortization:
Prior service costs	3			—			2			1			—
Net (gain)/loss	37			10			13			1			1
Net cost	$	16		$	3		$	2		$	1		$	1
Six Months Ended June 30, 2016
Service cost	$	124		$	29		$	35		$	6		$	6
Interest cost	201			48			68			9			10
Expected return on plan assets	(374		)	(92		)	(129		)	(17		)	(17		)
Amortization:
Prior service costs	7			1			3			1			—
Net (gain)/loss	75			20			27			3			3
Net cost	$	33		$	6		$	4		$	2		$	2
Three Months Ended June 30, 2015
Service cost	$	64		$	15		$	18		$	3		$	3
Interest cost	111			27			39			5			6
Expected return on plan assets	(181		)	(44		)	(63		)	(8		)	(9		)
Amortization:
Prior service costs	7			1			2			—			1
Net (gain)/loss	54			13			19			2			2
Net cost	$	55		$	12		$	15		$	2		$	3
Six Months Ended June 30, 2015
Service cost	$	128		$	30		$	36		$	6		$	6
Interest cost	222			53			77			10			11
Expected return on plan assets	(362		)	(89		)	(126		)	(16		)	(17		)
Amortization:
Prior service costs	13			3			5			—			1
Net (gain)/loss	108			27			38			5			5
Net cost	$	109		$	24		$	30		$	5		$	6

168

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Postretirement Benefits	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power
	(in millions)
Three Months Ended June 30, 2016
Service cost	$	6		$	2		$	1		$	1		$	1
Interest cost	17			4			7			—			1
Expected return on plan assets	(14		)	(7		)	(5		)	(1		)	(1		)
Amortization:
Prior service costs	1			1			1			—			—
Net (gain)/loss	4			1			2			—			—
Net cost	$	14		$	1		$	6		$	—		$	1
Six Months Ended June 30, 2016
Service cost	$	11		$	3		$	3		$	1		$	1
Interest cost	35			9			15			1			2
Expected return on plan assets	(28		)	(13		)	(11		)	(1		)	(1		)
Amortization:
Prior service costs	3			2			1			—			—
Net (gain)/loss	7			1			4			—			—
Net cost	$	28		$	2		$	12		$	1		$	2
Three Months Ended June 30, 2015
Service cost	$	5		$	2		$	1		$	—		$	1
Interest cost	20			5			9			1			1
Expected return on plan assets	(14		)	(7		)	(6		)	(1		)	(1		)
Amortization:
Prior service costs	1			—			—			—			—
Net (gain)/loss	4			1			3			—			—
Net cost	$	16		$	1		$	7		$	—		$	1
Six Months Ended June 30, 2015
Service cost	$	11		$	3		$	3		$	—		$	1
Interest cost	39			10			17			2			2
Expected return on plan assets	(29		)	(13		)	(12		)	(1		)	(1		)
Amortization:
Prior service costs	2			1			—			—			—
Net (gain)/loss	9			1			6			—			—
Net cost	$	32		$	2		$	14		$	1		$	2

169

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

(G) INCOME TAXES

See Note 5 to the financial statements of each registrant in Item 8 of the Form 10-K for additional tax information.

Current and Deferred Income Taxes

Tax Credit Carryforwards

Southern Company has federal ITC and PTC carryforwards totaling $801 million and $16 million, respectively, at June 30, 2016 (comprised primarily of $784 million and $16 million of ITC and PTC carryforwards, respectively, at Southern Power). These ITC and PTC carryforwards increased from $554 million and $1 million, respectively, as of December 31, 2015 (comprised primarily of $551 million and $1 million of ITC and PTC carryforwards, respectively, at Southern Power). Additionally, Southern Company has $208 million of state ITC carryforwards for the state of Georgia as of June 30, 2016, compared to $188 million at December 31, 2015.

The federal ITC carryforwards as of June 30, 2016 begin expiring in 2034 but are expected to be utilized by the end of 2021. The PTC carryforwards as of June 30, 2016 begin expiring in 2035 but are expected to be utilized by the end of 2020. The state ITC carryforwards for the state of Georgia as of June 30, 2016 expire between 2020 and 2026 but are expected to be fully utilized by the end of 2022.

Effective Tax Rate

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 30.4% for the six months ended June 30, 2016 compared to 32.9% for the corresponding period in 2015. The effective tax rate decrease was primarily due to increased federal income tax benefits from ITCs and PTCs at Southern Power and increased tax benefits related to the estimated probable losses on Mississippi Power's construction of the Kemper IGCC, partially offset by the impact of additional state income tax benefits recognized in 2015.

Mississippi Power

Mississippi Power's effective tax rate (benefit rate) was (205.6)% for the six months ended June 30, 2016 compared to 19.0% for the corresponding period in 2015. The effective tax rate decrease was primarily due to increased tax benefits related to the estimated probable losses on construction of the Kemper IGCC.

Southern Power

Southern Power's effective tax rate (benefit rate) was (74.0)% for the six months ended June 30, 2016 compared to 13.7% 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.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

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	—		9		10
Balance as of June 30, 2016	$	421	$	17	$	443

The tax positions from current periods primarily relate to federal income tax benefits from ITCs impacting the estimated annual effective tax rate for interim reporting purposes.

The impact on the effective tax rate, if recognized, is as follows:

	As of June 30, 2016							As of December 31, 2015
	Mississippi Power			Southern Power		Southern Company		Southern Company
	(in millions)
Tax positions impacting the effective tax rate	$	(2	)	$	17	$	20	$	10
Tax positions not impacting the effective tax rate	423			—		423		423
Balance of unrecognized tax benefits	$	421		$	17	$	443	$	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 all tax positions other than Section 174 R&E deductions disclosed below 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

171

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

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 $15 million as of June 30, 2016. The ultimate outcome of this matter cannot be determined at this time.

(H) DERIVATIVES

Southern Company, the traditional electric operating companies, and Southern Power are exposed to market risks, primarily commodity price risk and interest rate risk and occasionally foreign currency risk. To manage the volatility attributable to these exposures, each company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to each company's policies in areas such as counterparty exposure and risk management practices. Each company's policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a gross basis. See Note (C) 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. The cash impacts of settled foreign currency derivatives are classified as operating or financing activities to correspond with classification of the hedged interest or principal, respectively.

Energy-Related Derivatives

The traditional electric 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 electric operating companies have limited exposure to market volatility in commodity fuel prices and prices of electricity. Each of the traditional electric 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 electric 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 electric 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 electric 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.

172

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

At June 30, 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	250	2020	2016
Alabama Power	60	2019	—
Georgia Power	82	2019	—
Gulf Power	66	2020	—
Mississippi Power	29	2019	—
Southern Power	13	2017	2016

In addition to the volumes discussed in the above table, the traditional electric 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 3 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 June 30, 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.

173

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

At June 30, 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 June 30, 2016
	(in millions)							(in millions)
Cash Flow Hedges of Forecasted Debt
Gulf Power	$	80		3-month LIBOR	2.32%	December 2026		$	(7	)
Cash Flow Hedges of Existing Debt
Southern Company	8		(d)	3-month LIBOR	1.73%	June 2020		—
Southern Company	3		(d)	3-month LIBOR	1.73%	June 2020		—
Georgia Power	200			3-month LIBOR + 0.40%	1.01%	August 2016		—
Fair Value Hedges of Existing Debt
Southern Company	250			1.30%	3-month LIBOR + 0.17%	August 2017		2
Southern Company	300			2.75%	3-month LIBOR + 0.92%	June 2020		11
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	$	1,968						$	20

(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.

174

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

The estimated pre-tax gains (losses) expected to be reclassified from accumulated OCI to interest expense for the next 12-month period ending June 30, 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.

Foreign Currency Derivatives

Southern Company and certain subsidiaries may also enter into foreign currency derivatives to hedge exposure to changes in foreign currency exchange rates, such as that arising from the issuance of debt denominated in a currency other than U.S. dollars. Derivatives related to 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 that the hedged transactions affect earnings, including currency gains or losses arising from changes in the U.S. currency exchange rates. Any ineffectiveness is recorded directly to earnings. The derivatives employed as hedging instruments are structured to minimize ineffectiveness.

At June 30, 2016, the following foreign currency derivatives were outstanding:

	Pay Notional		Pay Rate	Receive Notional		Receive Rate	Hedge Maturity Date	Fair Value Gain (Loss) at June 30, 2016
	(in millions)			(in millions)				(in millions)
Cash Flow Hedges of Existing Debt
Southern Power	$	677	2.95%	€	600	1.00%	June 2022	$	(17	)
Southern Power	564		3.78%	500		1.85%	June 2026	(21		)
Total	$	1,241		€	1,100			$	(38	)

The estimated pre-tax gains (losses) that will be reclassified from accumulated OCI to earnings for the next 12-month period ending June 30, 2017 are $(24) million for Southern Company and Southern Power.

175

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Derivative Financial Statement Presentation and Amounts

At June 30, 2016, the fair value of energy-related derivatives, interest rate derivatives, and foreign currency derivatives was reflected in the balance sheets as follows:

Asset Derivatives at June 30, 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	$	12	$	5	$	6	$	1	$	—
Other deferred charges and assets	16		5		9		1		1
Total derivatives designated as hedging instruments for regulatory purposes	$	28	$	10	$	15	$	2	$	1	N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Other current assets	$	5	$	—	$	—	$	—	$	—	$	5
Other deferred charges and assets	1		—		—		—		—		1
Interest rate derivatives:
Other current assets	11		—		6		—		—		—
Other deferred charges and assets	16		—		8		—		—		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	33	$	—	$	14	$	—	$	—	$	6
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets	$	2	$	—	$	—	$	—	$	—	$	2
Total asset derivatives	$	63	$	10	$	29	$	2	$	1	$	8

176

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Liability Derivatives at June 30, 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(*)	$	61	$	17	$	4	$	25	$	15
Other deferred credits and liabilities	44		5		1		30		8
Total derivatives designated as hedging instruments for regulatory purposes	$	105	$	22	$	5	$	55	$	23	N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Liabilities from risk management activities(*)	$	3	$	—	$	—	$	—	$	—	$	3
Other deferred credits and liabilities	1		—		—		—		—		1
Interest rate derivatives:
Liabilities from risk management activities(*)	7		—		—		7		—		—
Foreign currency derivatives:
Liabilities from risk management activities(*)	24		—		—		—		—		24
Other deferred credits and liabilities	14		—		—		—		—		14
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	49	$	—	$	—	$	7	$	—	$	42
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current liabilities	$	1	$	—	$	—	$	—	$	—	$	1
Total liability derivatives	$	155	$	22	$	5	$	62	$	23	$	43

(*) Georgia Power, Mississippi Power, and Southern Power include current liabilities related to derivatives in "Other current liabilities."

177

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

At December 31, 2015, the fair value of energy-related derivatives and interest rate derivatives was reflected in the balance sheets as follows:

Asset Derivatives at December 31, 2015
	Fair Value
Derivative Category and Balance Sheet Location	Southern Company		Alabama Power		Georgia Power		Gulf Power		Mississippi Power		Southern Power
	(in millions)
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets	$	3	$	1	$	2	$	—	$	—	N/A
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Other current assets	$	3	$	—	$	—	$	—	$	—	$	3
Interest rate derivatives:
Other current assets	19		—		5		1		—		—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	22	$	—	$	5	$	1	$	—	$	3
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets	$	1	$	—	$	—	$	—	$	—	$	1
Interest rate derivatives:
Other current assets	3		—		—		—		—		3
Total derivatives not designated as hedging instruments	$	4	$	—	$	—	$	—	$	—	$	4
Total asset derivatives	$	29	$	1	$	7	$	1	$	—	$	7

178

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 electric 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, interest rate derivative contracts, and foreign currency derivative contracts at June 30, 2016 and December 31, 2015 are presented in the following tables.

179

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Derivative Contracts at June 30, 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)	$	36		$	10		$	15		$	2		$	1		$	8
Gross amounts not offset in the Balance Sheet (b)	(32		)	(8		)	(4		)	(2		)	(1		)	(3		)
Net energy-related derivative assets	$	4		$	2		$	11		$	—		$	—		$	5
Interest rate and foreign currency derivatives:
Interest rate and foreign currency derivatives presented in the Balance Sheet (a)	$	27		$	—		$	14		$	—		$	—		$	—
Gross amounts not offset in the Balance Sheet (b)	(18		)	—			—			—			—			—
Net interest rate and foreign currency derivative assets	$	9		$	—		$	14		$	—		$	—		$	—
Liabilities
Energy-related derivatives:
Energy-related derivatives presented in the Balance Sheet (a)	$	110		$	22		$	5		$	55		$	23		$	5
Gross amounts not offset in the Balance Sheet (b)	(32		)	(8		)	(4		)	(2		)	(1		)	(3		)
Net energy-related derivative liabilities	$	78		$	14		$	1		$	53		$	22		$	2
Interest rate and foreign currency derivatives:
Interest rate and foreign currency derivatives presented in the Balance Sheet (a)	$	45		$	—		$	—		$	7		$	—		$	38
Gross amounts not offset in the Balance Sheet (b)	(18		)	—			—			—			—			—
Net interest rate and foreign currency derivative liabilities	$	27		$	—		$	—		$	7		$	—		$	38

(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.

180

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	$	—	$	3
Gross amounts not offset in the Balance Sheet (b)	(9		)	—			(4		)	—		—		—
Net interest rate derivative assets	$	13		$	—		$	1		$	1	$	—	$	3
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.

181

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

At June 30, 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 June 30, 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	$	(61	)	$	(17	)	$	(4	)	$	(25	)	$	(15	)
Other regulatory assets, deferred	(44		)	(5		)	(1		)	(30		)	(8		)
Other regulatory liabilities, current (a)	12			5			6			1			—
Other regulatory liabilities, deferred (b)	16			5			9			1			1
Total energy-related derivative gains (losses)	$	(77	)	$	(12	)	$	10		$	(53	)	$	(22	)

(a) Georgia Power includes 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	)

(*) Georgia Power includes other regulatory liabilities, current in other current liabilities.

182

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

For the three months ended June 30, 2016 and 2015, the pre-tax effects of interest rate derivatives and foreign currency 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	$	6		$	31	Interest expense, net of amounts capitalized	$	(4	)	$	(2	)
Foreign currency derivatives	(39		)	—		Interest expense, net of amounts capitalized	(1		)	—
						Other income (expense), net	(20		)	—
Total	$	(33	)	$	31		$	(25	)	$	(2	)
Alabama Power
Interest rate derivatives	$	—		$	7	Interest expense, net of amounts capitalized	$	(2	)	$	(1	)
Georgia Power
Interest rate derivatives	$	—		$	24	Interest expense, net of amounts capitalized	$	(1	)	$	(1	)
Gulf Power
Interest rate derivatives	$	(2	)	$	—	Interest expense, net of amounts capitalized	$	—		$	—
Southern Power
Foreign currency derivatives	$	(39	)	$	—	Interest expense, net of amounts capitalized	$	(1	)	$	—
						Other income (expense), net	(20		)	—
Total	$	(39	)	$	—		$	(21	)	$	—

183

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

For the six months ended June 30, 2016 and 2015, the pre-tax effects of interest rate derivatives and foreign currency derivatives designated as cash flow hedging instruments recognized in OCI and those reclassified from accumulated OCI into earnings 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	$	(184	)	$	2	Interest expense, net of amounts capitalized	$	(7	)	$	(4	)
Foreign currency derivatives	(39		)	—		Interest expense, net of amounts capitalized	(1		)	—
						Other income (expense), net	(20		)	—
Total	$	(223	)	$	2		$	(28	)	$	(4	)
Alabama Power
Interest rate derivatives	$	(4	)	$	1	Interest expense, net of amounts capitalized	$	(3	)	$	(1	)
Georgia Power
Interest rate derivatives	$	—		$	1	Interest expense, net of amounts capitalized	$	(2	)	$	(2	)
Gulf Power
Interest rate derivatives	$	(7	)	$	—	Interest expense, net of amounts capitalized	$	—		$	—
Mississippi Power
Interest rate derivatives	$	—		$	—	Interest expense, net of amounts capitalized	$	(1	)	$	(1	)
Southern Power
Interest rate derivatives	$	—		$	—	Interest expense, net of amounts capitalized	$	(1	)	$	—
Foreign currency derivatives	(39		)	—		Interest expense, net of amounts capitalized	(1		)	—
						Other income (expense), net	(20		)	—
Total	$	(39	)	$	—		$	(22	)	$	—

For the three and six months ended June 30, 2016 and 2015, the pre-tax effects of energy-related derivatives designated as cash flow hedging instruments recognized in OCI and those reclassified from accumulated OCI into earnings were immaterial for all registrants.

For the three months ended June 30, 2016 and 2015, the pre-tax effects of interest rate derivatives designated as fair value hedging instruments were immaterial on a gross basis for all registrants.

For the six months ended June 30, 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	$	24	$	4
Georgia Power
Interest rate derivatives:	Interest expense, net of amounts capitalized	$	15	$	2

184

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

For the three and six months ended June 30, 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 and six months ended June 30, 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 June 30, 2016, the registrants' collateral posted with their derivative counterparties was immaterial.

At June 30, 2016, the fair value of derivative liabilities with contingent features was $24 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 $24 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 electric operating companies, and Southern Power are exposed to losses related to financial instruments in the event of counterparties' nonperformance. Southern Company, the traditional electric 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 electric 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 electric operating companies', and Southern Power's exposure to counterparty credit risk. Therefore, Southern Company, the traditional electric 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

Merger with Southern Company Gas

Southern Company Gas, formerly known as AGL Resources Inc., is an energy services holding company whose primary business is the distribution of natural gas through natural gas distribution utilities. On July 1, 2016, Southern Company completed the Merger for a total purchase price of approximately $8.0 billion and Southern Company Gas became a wholly-owned, direct subsidiary of Southern Company.

185

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

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 Southern Company Gas' assets and liabilities will be recorded as goodwill. The following table presents the preliminary purchase price allocation:

Southern Company Gas Purchase Price	June 30, 2016
	(in millions)
Current assets	$	1,474
Property, plant, and equipment	9,795
Goodwill	6,333
Intangible assets	436
Regulatory assets	846
Other assets	273
Current liabilities	(2,205		)
Other liabilities	(4,529		)
Long-term debt	(4,261		)
Noncontrolling interests	(160		)
Total purchase price	$	8,002

The estimated fair values noted above are preliminary and are subject to change upon finalization of the purchase accounting assessment as additional information related to the fair value of assets and liabilities becomes available. Subsequent adjustments to the preliminary purchase price allocation may have a material impact on the results of operations and financial position of Southern Company.

During the three and six months ended June 30, 2016, Southern Company recorded in its statements of income external transaction costs for financing, legal, and consulting services associated with the Merger of approximately $43.4 million and $63.3 million, respectively, of which $26.9 million and $32.9 million is included in operating expenses and $16.5 million and $30.4 million is included in other income and (expense), respectively.

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.

Acquisition of PowerSecure International, Inc.

On May 9, 2016, Southern Company acquired all of the outstanding stock of PowerSecure, a leading provider of products and services in the areas of distributed generation, energy efficiency, and utility infrastructure, for $18.75 per common share in cash, resulting in an aggregate purchase price of $429 million. As a result, PowerSecure became a wholly-owned subsidiary of Southern Company.

186

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

The aggregate purchase price was allocated on a preliminary basis to the assets acquired and liabilities assumed based upon the current determination of fair values at the date of acquisition. The preliminary allocation of the purchase price is as follows:

PowerSecure Purchase Price	June 30, 2016
	(in millions)
Current assets	$	174
Property, plant, and equipment	48
Goodwill	262
Intangible assets	99
Other assets	8
Current liabilities	(111		)
Long-term debt, including current portion	(47		)
Deferred credits and other liabilities	(4		)
Total purchase price	$	429

The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed of $262 million was recognized as goodwill, which is primarily attributable to the expected business expansion opportunities for PowerSecure. Southern Company anticipates that the majority of the value assigned to goodwill will not be deductible for tax purposes. Assumptions and estimates underlying the fair value adjustments are subject to change pending further review of the assets acquired and liabilities assumed.

The preliminary valuation of identifiable intangible assets included customer relationships, trade names, patents, and backlog with estimated lives of three to 26 years. The estimated fair value measurements of identifiable intangible assets were primarily based on significant unobservable inputs (Level 3).

The results of operations for PowerSecure have been included in the consolidated financial statements from the date of acquisition and are immaterial to the consolidated financial results of Southern Company. Pro forma results of operations have not been presented for the acquisition because the effects of the acquisition were immaterial to Southern Company's consolidated financial results for all periods presented.

Natural Gas Pipeline Venture

On July 10, 2016, Southern Company and Kinder Morgan, Inc. (Kinder Morgan) entered into a definitive agreement under which Southern Company will acquire a 50% equity interest in Southern Natural Gas Company, L.L.C. (SNG), which is the owner of a 7,600-mile pipeline system connecting natural gas supply basins in Texas, Louisiana, Mississippi, Alabama, and the Gulf of Mexico to markets in Louisiana, Mississippi, Alabama, Florida, Georgia, South Carolina, and Tennessee. Southern Company expects to finance the purchase price of approximately $1.5 billion with a mix of equity and debt in a credit-supportive manner. Southern Company's investment in SNG will be accounted for under the equity method of accounting.

The transaction is subject to the notification and clearance and reporting requirements under the Hart-Scott-Rodino Antitrust Improvements Act of 1976. Southern Company and Kinder Morgan expect to complete the transaction in the third quarter or early in the fourth quarter 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 six months ended June 30, 2016, the fair values of the assets and liabilities acquired of Garland, Garland A, Lost Hills Blackwell, Morelos, North Star, and Roserock were finalized and there were no changes.

187

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

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 discussed below. Acquisition-related costs were expensed as incurred and were not material. The acquisitions do not include any contingent consideration unless specifically noted.

Project Facility	Resource	Seller; Acquisition Date	Approx. Nameplate Capacity	Location	Southern Power Percentage Ownership			Expected/Actual COD	PPA Counterparties for Plant Output	PPA Contract Period
			(MW)
Acquisitions for the Six Months Ended June 30, 2016
Calipatria	Solar	Solar Frontier Americas Holding LLC February 11, 2016	20	Imperial County, CA	90	%		February 2016	San Diego Gas & Electric Company	20 years
East Pecos	Solar	First Solar, Inc. March 4, 2016	120	Pecos County, TX	100	%		Fourth quarter 2016	Austin Energy	15 years
Grant Wind	Wind	Apex Clean Energy Holdings, LLC April 7, 2016	151	Grant County, OK	100	%		April 2016	Western Farmers, East Texas, and Northeast Texas Electric Cooperative	20 years
Passadumkeag	Wind	Quantum Utility Generation, LLC June 30, 2016	42	Penobscot County, ME	100	%		July 2016	Western Massachusetts Electric Company	15 years
Acquisitions Subsequent to June 30, 2016
Henrietta	Solar	SunPower Corp. July 1, 2016	102	Kings County, CA	51	%	(*)	July 2016	Pacific Gas and Electric Company	20 years
Lamesa	Solar	RES America Developments Inc. July 1, 2016	102	Dawson County, TX	100	%		Second quarter 2017	City of Garland, Texas	15 years
Rutherford	Solar	Cypress Creek Renewables, LLC July 1, 2016	74	Rutherford County, NC	90	%		Fourth quarter 2016	Duke Energy Carolinas, LLC	15 years

(*) 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. In addition, Southern Power is entitled to substantially all of the federal tax benefits with respect to the transaction.

Acquisitions During the Six Months Ended June 30, 2016

Southern Power's aggregate purchase price for the project facilities acquired during the six months ended June 30, 2016 is approximately $477 million, which includes $6 million of contingent consideration. Including the minority owner Turner Renewable Energy, LLC's (TRE) 10% ownership interest in Calipatria, the total aggregate purchase price is approximately $483 million for the project facilities acquired during the six months ended June 30, 2016. The fair values of the assets and liabilities acquired through the business combinations were recorded as follows: $426 million as CWIP, $58 million as property, plant, and equipment, $4 million as other assets, and $7 million as accounts payable; however, the allocations of the purchase price to individual assets have not been finalized. For East Pecos, which is currently under construction, total construction costs, excluding the acquisition costs, are expected to be approximately $160 million to $180 million. The ultimate outcome of this matter cannot be determined at this time.

188

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Acquisitions Subsequent to June 30, 2016

Southern Power's aggregate purchase price for acquisitions subsequent to June 30, 2016 is approximately $275 million. Including the minority owner, SunPower Corp.'s 49% ownership interest in Henrietta, and TRE's 10% ownership interest in Rutherford, the aggregate total purchase price is approximately $447 million for the project facilities acquired subsequent to June 30, 2016. The aggregate purchase price includes the assumption of $217 million in construction debt (non-recourse to Southern Power). For Lamesa and Rutherford, which are currently under construction, total aggregate construction costs, excluding the acquisition costs, are expected to be approximately $260 million to $300 million. The ultimate outcome of these matters cannot be determined at this time.

Acquisition Agreements Executed but Not Yet Closed

During the six months ended June 30, 2016 and subsequent to that date, Southern Power entered into agreements to acquire the following projects for an aggregate purchase price of $1.1 billion: 100% ownership interests in two wind facilities totaling 299 MWs in Texas, significantly covered with PPAs for the first 12 to 14 years of operation; a 51% ownership interest (through 100% ownership of the Class A membership interests entitling Southern Power to 51% of all cash distributions and significantly all of the federal tax benefits) in a 100-MW solar facility in Nevada with a 20-year PPA; and a 90.1% ownership interest in a 257-MW wind facility in Texas significantly covered with a 12-year PPA. These acquisitions are expected to close in the third and fourth quarters of 2016. The ultimate outcome of these matters cannot be determined at this time.

The aggregate amount of revenue recognized by Southern Power related to the project facilities acquired during the six months ended June 30, 2016 included in the consolidated statement of income for year-to-date 2016 is $4 million. The aggregate amount of net income, excluding impacts of ITCs and PTCs, attributable to Southern Power related to the project facilities acquired during the six months ended June 30, 2016 included in the consolidated statement of income is immaterial. These businesses did not have operating revenues or activities prior to completion of construction and their assets being placed in service; therefore, supplemental pro forma information as though the acquisitions occurred as of the beginning of 2016 and for the comparable 2015 period is not meaningful and has been omitted.

Construction Projects

During the six months ended June 30, 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 June 30, 2016, total costs of construction incurred for the projects below were $2.7 billion, of which $1.7 billion remains in CWIP. Including the total construction costs incurred to date and the acquisition prices allocated to CWIP, total aggregate construction costs for the projects below are estimated to be approximately $3.0 billion to $3.2 billion. The ultimate outcome of these matters cannot be determined at this time.

189

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Solar Facility	Seller	Approx. Nameplate Capacity	Location	Expected/Actual COD	PPA Counterparties for Plant Output	PPA Contract Period
		(MW)
Butler	CERSM, LLC and Community Energy, Inc.	103	Taylor County, GA	Fourth quarter 2016	Georgia Power(a)	30 years
Desert Stateline(b)	First Solar Development, LLC	299(c)	San Bernardino County, CA	Through third quarter 2016	Southern California Edison Company (SCE)	20 years
Garland and Garland A	Recurrent Energy, LLC	205	Kern County, CA	Fourth quarter 2016 and Third quarter 2016	SCE	15 years and 20 years
Roserock	Recurrent Energy, LLC	160	Pecos County, TX	Fourth quarter 2016	Austin Energy	20 years
Sandhills	N/A	146	Taylor County, GA	Fourth quarter 2016	Cobb, Flint, Irwin, Middle Georgia and Sawnee Electric Membership Corporations	25 years
Tranquillity	Recurrent Energy, LLC	205	Fresno County, CA	July 2016	Shell Energy North America (US), LP/SCE	18 years

(a) Butler - Affiliate PPA approved by the FERC.

(b) 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.

(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 152 MWs were placed in service during the six months ended June 30, 2016. Subsequent to June 30, 2016, 37 MWs were placed in service.

190

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

(J) SEGMENT AND RELATED INFORMATION

The primary business of the Southern Company system is electricity sales by the traditional electric operating companies and Southern Power. The four traditional electric 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 electric operating companies and Southern Power. Revenues from sales by Southern Power to the traditional electric operating companies were $107 million and $204 million for the three and six months ended June 30, 2016, respectively, and $85 million and $199 million for the three and six months ended June 30, 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 products and services in the areas of distributed generation, energy efficiency, and utility infrastructure, as well as investments in telecommunications and leveraged lease projects. All other inter-segment revenues are not material.

Financial data for business segments and products and services for the three and six months ended June 30, 2016 and 2015 was as follows:

	Electric Utilities
	Traditional Electric Operating Companies		Southern Power		Eliminations			Total		All Other			Eliminations			Consolidated
	(in millions)
Three Months Ended June 30, 2016:
Operating revenues	$	4,115	$	373	$	(109	)	$	4,379	$	125		$	(45	)	$	4,459
Segment net income (loss)(a)(b)	595		89		—			684		(68		)	(4		)	612
Six Months Ended June 30, 2016:
Operating revenues	$	7,884	$	688	$	(212	)	$	8,360	$	172		$	(81	)	$	8,451
Segment net income (loss)(a)(c)	1,059		139		—			1,198		(94		)	(7		)	1,097
Total assets at June 30, 2016	$	70,706	$	11,082	$	(425	)	$	81,363	$	10,505		$	(995	)	$	90,873
Three Months Ended June 30, 2015:
Operating revenues	$	4,077	$	337	$	(90	)	$	4,324	$	43		$	(30	)	$	4,337
Segment net income (loss)(a)(b)	561		46		—			607		18			4			629
Six Months Ended June 30, 2015:
Operating revenues	$	8,025	$	684	$	(213	)	$	8,496	$	83		$	(59	)	$	8,520
Segment net income (loss)(a)(c)	1,038		79		—			1,117		21			—			1,138
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 electric operating companies includes pre-tax charges for estimated probable losses on the Kemper IGCC of $81 million ($50 million after tax) and $23 million ($14 million after tax) for the three months ended June 30, 2016 and 2015, respectively. See Note (B) under "Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" for additional information.

(c) Segment net income (loss) for the traditional electric operating companies includes pre-tax charges for estimated probable losses on the Kemper IGCC of $134 million ($83 million after tax) and $32 million ($20 million after tax) for the six months ended June 30, 2016 and 2015, respectively. See Note (B) under "Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" for additional information.

191

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Products and Services

	Electric Utilities' Revenues
Period	Retail		Wholesale		Other		Total
	(in millions)
Three Months Ended June 30, 2016	$	3,748	$	446	$	185	$	4,379
Three Months Ended June 30, 2015	3,714		448		162		4,324
Six Months Ended June 30, 2016	$	7,124	$	842	$	394	$	8,360
Six Months Ended June 30, 2015	7,256		915		325		8,496

192

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. Except as described below, there have been no material changes to these risk factors from those previously disclosed in the Form 10-K.

With the completion of the Merger, Southern Company now owns Southern Company Gas, a company whose subsidiaries own and operate a natural gas business.

Southern Company Gas is an energy services holding company whose primary business is the distribution of natural gas through natural gas distribution utilities. Southern Company Gas is involved in several other businesses that are mainly related and complementary to its primary business including: retail operations including the provision of natural gas commodity and related services to customers in competitive markets or markets that provide for customer choice, wholesale services including natural gas storage, gas pipeline arbitrage, and natural gas asset management and/or related logistics services, and midstream operations including high deliverability natural gas storage facilities and select pipelines. As a result, Southern Company is now subject to risks to which it was not previously subject and Southern Company stockholders may be adversely affected by these risks. These risks include the following:

• Transporting and storing natural gas involves risks that may result in accidents and other operating risks and costs. Southern Company Gas' natural gas distribution and storage activities involve a variety of inherent hazards and operating risks, such as leaks, accidents, explosions, and mechanical problems, which could result in serious injury to employees and non-employees, loss of human life, significant damage to property, environmental pollution, and impairment of its operations.

• Southern Company Gas' natural gas business faces increasing competition. The natural gas business is highly competitive and increasingly complex. Southern Company Gas is facing increasing competition from other companies that supply energy, including electric, oil, and propane providers and, in some cases, energy marketing and trading companies.

• Southern Company Gas may experience reported net income volatility due to mark-to-market accounting. Southern Company Gas utilizes hedging instruments to lock in economic value in its wholesale natural gas segment, which are not designated as hedges for accounting purposes. The difference in accounting treatment for the underlying position and the financial instrument used to hedge the value of the contract can cause volatility in reported net income while the positions are open due to mark-to-market accounting.

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.

(3) Articles of Incorporation and By-Laws
Southern Company
(a)1	Certificate of Amendment to the Certificate of Incorporation of the Southern Company effective May 26, 2016. (Designated in Form 8-K dated May 25, 2016, File No. 1-3526, as Exhibit 3.1.)
(a)2	By-Laws of the Southern Company, as amended effective May 25, 2016. (Designated in Form 8-K dated May 25, 2016, File No. 1-3526, as Exhibit 3.2.)

193

		(4) Instruments Describing Rights of Security Holders, Including Indentures
		Southern Company
		(a)1	-	Twelfth Supplemental Indenture to Senior Note Indenture, dated as of May 24, 2016, providing for the issuance of the 1.55% Senior Notes due 2018. (Designated in Form 8-K dated May 19, 2016, File No. 1-3526, as Exhibit 4.2(a).)
		(a)2	-	Thirteenth Supplemental Indenture to Senior Note Indenture, dated as of May 24, 2016, providing for the issuance of the 1.85% Senior Notes due 2019. (Designated in Form 8-K dated May 19, 2016, File No. 1-3526, as Exhibit 4.2(b).)
		(a)3	-	Fourteenth Supplemental Indenture to Senior Note Indenture, dated as of May 24, 2016, providing for the issuance of the 2.35% Senior Notes due 2021. (Designated in Form 8-K dated May 19, 2016, File No. 1-3526, as Exhibit 4.2(c).)
		(a)4	-	Fifteenth Supplemental Indenture to Senior Note Indenture, dated as of May 24, 2016, providing for the issuance of the 2.95% Senior Notes due 2023. (Designated in Form 8-K dated May 19, 2016, File No. 1-3526, as Exhibit 4.2(d).)
		(a)5	-	Sixteenth Supplemental Indenture to Senior Note Indenture, dated as of May 24, 2016, providing for the issuance of the 3.25% Senior Notes due 2026. (Designated in Form 8-K dated May 19, 2016, File No. 1-3526, as Exhibit 4.2(e).)
		(a)6	-	Seventeenth Supplemental Indenture to Senior Note Indenture, dated as of May 24, 2016, providing for the issuance of the 4.25% Senior Notes due 2036. (Designated in Form 8-K dated May 19, 2016, File No. 1-3526, as Exhibit 4.2(f).)
		(a)7	-	Eighteenth Supplemental Indenture to Senior Note Indenture, dated as of May 24, 2016, providing for the issuance of the 4.40% Senior Notes due 2046. (Designated in Form 8-K dated May 19, 2016, File No. 1-3526, as Exhibit 4.2(g).)
		Southern Power
		(f)1	-	Tenth Supplemental Indenture to Senior Note Indenture, dated as of June 20, 2016, providing for the issuance of the Series 2016A 1.000% Senior Notes due June 20, 2022. (Designated in Form 8-K dated June 13, 2016, File No. 001-37803, as Exhibit 4.4(a).)
		(f)2	-	Eleventh Supplemental Indenture to Senior Note Indenture, dated as of June 20, 2016, providing for the issuance of the Series 2016B 1.850% Senior Notes due June 20, 2026. (Designated in Form 8-K dated June 13, 2016, File No. 001-37803, as Exhibit 4.4(b).)
		(10) Material Contracts
		Southern Company
#	*	(a)1	-	The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective June 30, 2016.
#	*	(a)2	-	The Southern Company Supplemental Benefit Plan, Amended and Restated effective June 30, 2016.
		Alabama Power
#		(b)1	-	The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective June 30, 2016. See Exhibit 10(a)1 herein.
#		(b)2	-	The Southern Company Supplemental Benefit Plan, Amended and Restated effective June 30, 2016. See Exhibit 10(a)2 herein.
		Georgia Power
#		(c)1	-	The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective June 30, 2016. See Exhibit 10(a)1 herein.

194

#		(c)2	-	The Southern Company Supplemental Benefit Plan, Amended and Restated effective June 30, 2016. See Exhibit 10(a)2 herein.
	*	(c)3	-	Amendment No. 8 dated as of April 20, 2016, to Engineering, Procurement and Construction Agreement, dated as of April 8, 2008, between Georgia Power, for itself and as agent for Oglethorpe Power Corporation, Municipal Electric Authority of Georgia, and Dalton Utilities, as owners, and a consortium consisting of Westinghouse Electric Company LLC and CB&I Stone & Webster, Inc., as contractor, for Units 3&4 at the Vogtle Electric Generating Plant Site. (Georgia Power has requested confidential treatment for certain portions of this document pursuant to an application for confidential treatment sent to the SEC. Georgia Power omitted such portions from the filing and filed them separately with the SEC.)
		Gulf Power
#		(d)1	-	The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective June 30, 2016. See Exhibit 10(a)1 herein.
#		(d)2	-	The Southern Company Supplemental Benefit Plan, Amended and Restated effective June 30, 2016. See Exhibit 10(a)2 herein.
		Mississippi Power
#		(e)1	-	The Southern Company Supplemental Executive Retirement Plan, Amended and Restated effective June 30, 2016. See Exhibit 10(a)1 herein.
#		(e)2	-	The Southern Company Supplemental Benefit Plan, Amended and Restated effective June 30, 2016. See Exhibit 10(a)2 herein.
		(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).)
		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.)

195

	(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.
	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.

196

	(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) Interactive Data Files
*	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

197

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: August 8, 2016

198

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: August 8, 2016

199

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: August 8, 2016

200

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: August 8, 2016

201

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: August 8, 2016

202

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

Date: August 8, 2016

203