10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

þQUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2018

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
1-14174	Southern Company Gas (A Georgia Corporation) Ten Peachtree Place, N.E. Atlanta, Georgia 30309 (404) 584-4000	58-2210952

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, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act. (Check one):

Registrant	Large Accelerated Filer	Accelerated Filer	Non- accelerated Filer	Smaller Reporting Company	Emerging Growth 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
Southern Company Gas			X

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨

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, 2018
The Southern Company	Par Value $5 Per Share	1,014,136,083
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	7,392,717
Mississippi Power Company	Without Par Value	1,121,000
Southern Power Company	Par Value $0.01 Per Share	1,000
Southern Company Gas	Par Value $0.01 Per Share	100

This combined Form 10-Q is separately filed by The Southern Company, Alabama Power Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company, Southern Power Company, and Southern Company Gas. 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, 2018

		Page Number
DEFINITIONS		5
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION		8
	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	11
	Condensed Consolidated Statements of Comprehensive Income	12
	Condensed Consolidated Statements of Cash Flows	13
	Condensed Consolidated Balance Sheets	14
	Management's Discussion and Analysis of Financial Condition and Results of Operations	16
	Alabama Power Company
	Condensed Statements of Income	54
	Condensed Statements of Comprehensive Income	54
	Condensed Statements of Cash Flows	55
	Condensed Balance Sheets	56
	Management's Discussion and Analysis of Financial Condition and Results of Operations	58
	Georgia Power Company
	Condensed Statements of Income	74
	Condensed Statements of Comprehensive Income	74
	Condensed Statements of Cash Flows	75
	Condensed Balance Sheets	76
	Management's Discussion and Analysis of Financial Condition and Results of Operations	78
	Gulf Power Company
	Condensed Statements of Income	101
	Condensed Statements of Comprehensive Income	101
	Condensed Statements of Cash Flows	102
	Condensed Balance Sheets	103
	Management's Discussion and Analysis of Financial Condition and Results of Operations	105
	Mississippi Power Company
	Condensed Statements of Operations	120
	Condensed Statements of Comprehensive Income	120
	Condensed Statements of Cash Flows	121
	Condensed Balance Sheets	122
	Management's Discussion and Analysis of Financial Condition and Results of Operations	124
	Southern Power Company and Subsidiary Companies
	Condensed Consolidated Statements of Income	142
	Condensed Consolidated Statements of Comprehensive Income	142
	Condensed Consolidated Statements of Cash Flows	143
	Condensed Consolidated Balance Sheets	144
	Management's Discussion and Analysis of Financial Condition and Results of Operations	146

3

INDEX TO QUARTERLY REPORT ON FORM 10-Q

June 30, 2018

		Page Number
	PART I—FINANCIAL INFORMATION (CONTINUED)
	Southern Company Gas and Subsidiary Companies
	Condensed Consolidated Statements of Income	159
	Condensed Consolidated Statements of Comprehensive Income	159
	Condensed Consolidated Statements of Cash Flows	160
	Condensed Consolidated Balance Sheets	161
	Management's Discussion and Analysis of Financial Condition and Results of Operations	163
	Notes to the Condensed Financial Statements	187
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	52
Item 4.	Controls and Procedures	52
	PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	262
Item 1A.	Risk Factors	262
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	265
	Signatures	269

4

DEFINITIONS

Term	Meaning
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
ARO	Asset retirement obligation
ASC	Accounting Standards Codification
ASU	Accounting Standards Update
Atlanta Gas Light	Atlanta Gas Light Company, a wholly-owned subsidiary of Southern Company Gas
Atlantic Coast Pipeline	Atlantic Coast Pipeline, LLC, a joint venture to construct and operate a natural gas pipeline in which Southern Company Gas has a 5% ownership interest
Bechtel	Bechtel Power Corporation
CCR	Coal combustion residuals
CO2	Carbon dioxide
COD	Commercial operation date
Contractor Settlement Agreement	The December 31, 2015 agreement between Westinghouse and the Vogtle Owners resolving disputes between the Vogtle Owners and the EPC Contractor under the Vogtle 3 and 4 Agreement
Cooperative Energy	Electric cooperative in Mississippi
CPCN	Certificate of public convenience and necessity
Customer Refunds	Refunds to be issued to Georgia Power customers no later than the end of the third quarter 2018 as ordered by the Georgia PSC related to the Guarantee Settlement Agreement
CWIP	Construction work in progress
Dalton Pipeline	A 50% undivided ownership interest of Southern Company Gas in a pipeline facility in Georgia
DOE	U.S. Department of Energy
ECO Plan	Mississippi Power's environmental compliance overview plan
Eligible Project Costs	Certain costs of construction relating to Plant Vogtle Units 3 and 4 that are eligible for financing under the loan guarantee program established under Title XVII of the Energy Policy Act of 2005
EPA	U.S. Environmental Protection Agency
EPC Contractor	Westinghouse and its affiliate, WECTEC Global Project Services Inc.; the former engineering, procurement, and construction contractor for Plant Vogtle Units 3 and 4
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FFB	Federal Financing Bank
Fitch	Fitch Ratings, Inc.
Form 10-K	Annual Report on Form 10-K of Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Southern Power, and Southern Company Gas for the year ended December 31, 2017, as applicable
GAAP	U.S. generally accepted accounting principles
Georgia Power	Georgia Power Company
Guarantee Settlement Agreement	The June 9, 2017 settlement agreement between the Vogtle Owners and Toshiba related to the Toshiba Guarantee
Gulf Power	Gulf Power Company
Heating Degree Days	A measure of weather, calculated when the average daily temperatures are less than 65 degrees Fahrenheit
Horizon Pipeline	Horizon Pipeline Company, LLC
IGCC	Integrated coal gasification combined cycle, the technology originally approved for Mississippi Power's Kemper County energy facility (Plant Ratcliffe)
IIC	Intercompany interchange contract

5

DEFINITIONS

(continued)

Term	Meaning
Illinois Commission	Illinois Commerce Commission
Interim Assessment Agreement	Agreement entered into by the Vogtle Owners and the EPC Contractor to allow construction to continue after the EPC Contractor's bankruptcy filing
IRS	Internal Revenue Service
ITC	Investment tax credit
KWH	Kilowatt-hour
LIBOR	London Interbank Offered Rate
LIFO	Last-in, first-out
LNG	Liquefied natural gas
Loan Guarantee Agreement	Loan guarantee agreement entered into by Georgia Power with the DOE in 2014, under which the proceeds of borrowings may be used to reimburse Georgia Power for Eligible Project Costs incurred in connection with its construction of Plant Vogtle Units 3 and 4
LOCOM	Lower of weighted average cost or current market price
LTSA	Long-term service agreement
Merger	The merger, effective July 1, 2016, of a wholly-owned, direct subsidiary of Southern Company with and into Southern Company Gas, with Southern Company Gas continuing as the surviving corporation
Mississippi Power	Mississippi Power Company
mmBtu	Million British thermal units
Moody's	Moody's Investors Service, Inc.
MRA	Municipal and Rural Associations
MW	Megawatt
natural gas distribution utilities	Southern Company Gas' natural gas distribution utilities (Nicor Gas, Atlanta Gas Light, Virginia Natural Gas, Elizabethtown Gas, Florida City Gas, Chattanooga Gas Company, and Elkton Gas as of June 30, 2018) (Nicor Gas, Atlanta Gas Light, Virginia Natural Gas, and Chattanooga Gas Company as of July 29, 2018)
NCCR	Georgia Power's Nuclear Construction Cost Recovery
New Jersey BPU	New Jersey Board of Public Utilities
NextEra Energy	NextEra Energy, Inc.
Nicor Gas	Northern Illinois Gas Company, a wholly-owned subsidiary of Southern Company Gas
NRC	U.S. Nuclear Regulatory Commission
NYMEX	New York Mercantile Exchange, Inc.
OCI	Other comprehensive income
PennEast Pipeline	PennEast Pipeline Company, LLC, a joint venture to construct and operate a natural gas pipeline in which Southern Company Gas has a 20% ownership interest
PEP	Mississippi Power's Performance Evaluation Plan
Pivotal Home Solutions	Nicor Energy Services Company, until June 4, 2018 a wholly-owned subsidiary of Southern Company Gas, doing business as Pivotal Home Solutions
Pivotal Utility Holdings	Pivotal Utility Holdings, Inc., until July 29, 2018 a wholly-owned subsidiary of Southern Company Gas, doing business as Elizabethtown Gas (until July 1, 2018), Elkton Gas (until July 1, 2018), and Florida City Gas
PowerSecure	PowerSecure, Inc.
power pool	The operating arrangement whereby the integrated generating resources of the traditional electric operating companies and Southern Power (excluding subsidiaries) are subject to joint commitment and dispatch in order to serve their combined load obligations
PPA	Power purchase agreements, as well as, for Southern Power, contracts for differences that provide the owner of a renewable facility a certain fixed price for the electricity sold to the grid
PSC	Public Service Commission

6

DEFINITIONS

(continued)

Term	Meaning
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 ECR	Alabama Power's Rate Energy Cost Recovery
Rate NDR	Alabama Power's Rate Natural Disaster Reserve
Rate RSE	Alabama Power's Rate Stabilization and Equalization plan
registrants	Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Southern Power Company, and Southern Company Gas
ROE	Return on equity
S&P	S&P Global Ratings, a division of S&P Global Inc.
SCS	Southern Company Services, Inc. (the Southern Company system service company)
SEC	U.S. Securities and Exchange Commission
SNG	Southern Natural Gas Company, L.L.C.
Southern Company	The Southern Company
Southern Company Gas	Southern Company Gas and its subsidiaries
Southern Company Gas Capital	Southern Company Gas Capital Corporation, a 100%-owned subsidiary of Southern Company Gas
Southern Company system	Southern Company, the traditional electric operating companies, Southern Power, Southern Company Gas, Southern Electric Generating Company, Southern Nuclear, SCS, Southern Communications Services, Inc., PowerSecure, and other subsidiaries
Southern Nuclear	Southern Nuclear Operating Company, Inc.
Southern Power	Southern Power Company and its subsidiaries
SPSH	SP Solar Holdings I, LP
Tax Reform Legislation	The Tax Cuts and Jobs Act, which was signed into law on December 22, 2017 and became effective on January 1, 2018
Toshiba	Toshiba Corporation, parent company of Westinghouse
Toshiba Guarantee	Certain payment obligations of the EPC Contractor guaranteed by Toshiba
traditional electric operating companies	Alabama Power, Georgia Power, Gulf Power, and Mississippi Power
Triton	Triton Container Investments, LLC
VCM	Vogtle Construction Monitoring
Virginia Commission	Virginia State Corporation Commission
Virginia Natural Gas	Virginia Natural Gas, Inc., a wholly-owned subsidiary of Southern Company Gas
Vogtle 3 and 4 Agreement	Agreement entered into with the EPC Contractor in 2008 by Georgia Power, acting for itself and as agent for the Vogtle Owners, and rejected in bankruptcy in July 2017, pursuant to which the EPC Contractor agreed to design, engineer, procure, construct, and test Plant Vogtle Units 3 and 4
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
Vogtle Services Agreement	The June 9, 2017 services agreement between the Vogtle Owners and the EPC Contractor, as amended and restated on July 20, 2017, for the EPC Contractor to transition construction management of Plant Vogtle Units 3 and 4 to Southern Nuclear and to provide ongoing design, engineering, and procurement services to Southern Nuclear
WACOG	Weighted average cost of gas
Westinghouse	Westinghouse Electric Company LLC

7

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 regulated rates, the strategic goals for the wholesale business, customer and sales growth, economic conditions, fuel and environmental cost recovery and other rate actions, projected equity ratios, costs of modernization efforts, 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 construction projects, completion of announced acquisitions or dispositions, filings with state and federal regulatory authorities, impacts of the Tax Reform Legislation, federal and state 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 environmental laws and regulations governing air, water, land, and protection of other natural resources, 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;

• the uncertainty surrounding the Tax Reform Legislation, including implementing regulations and IRS interpretations, actions that may be taken in response by regulatory authorities, and its impact, if any, on the credit ratings of Southern Company and its subsidiaries;

• current and future litigation or regulatory investigations, proceedings, or inquiries;

• the effects, extent, and timing of the entry of additional competition in the markets in which Southern Company's subsidiaries operate, including from the development and deployment of alternative energy sources such as self-generation and distributed generation technologies;

• variations in demand for electricity and natural gas, including those relating to weather, the general economy, population and business growth (and declines), the effects of energy conservation and efficiency measures, and any potential economic impacts resulting from federal fiscal decisions;

• available sources and costs of natural gas and other fuels;

• limits on pipeline capacity;

• transmission constraints;

• effects of inflation;

• the ability to control costs and avoid cost and schedule overruns during the development, construction, and operation of facilities, including Plant Vogtle Units 3 and 4 which includes components based on new technology that is just beginning initial operation in the global nuclear industry at scale, including changes in labor costs, availability, and productivity, challenges with management of contractors, subcontractors, or vendors, adverse weather conditions, shortages, increased costs or inconsistent quality of equipment, materials, and labor, including any changes related to imposition of import tariffs, 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;

• the ability to construct facilities in accordance with the requirements of permits and licenses (including satisfaction of NRC requirements), 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 the Southern Company system's employee and retiree benefit plans and nuclear decommissioning trust funds;

• advances in technology;

• ongoing renewable energy partnerships and development agreements;

• 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;

• 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;

8

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

(continued)

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

• a decision by more than 10% of the owners of Plant Vogtle Units 3 and 4 not to proceed with construction;

• litigation or other disputes related to the Kemper County energy facility;

• 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, including the proposed dispositions of Gulf Power and Southern Power's plants located in Florida and the potential sale of a noncontrolling interest in Southern Power's wind facilities, 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 and the possibility that costs related to the integration of Southern Company and Southern Company Gas will be greater than expected;

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

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

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

• 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 foreign 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 electric utilities to obtain additional generating capacity (or sell excess generating capacity) at competitive prices;

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

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

• impairments of goodwill or long-lived assets;

• 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.

9

THE SOUTHERN COMPANY

AND SUBSIDIARY COMPANIES

10

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,
	2018			2017			2018			2017
	(in millions)						(in millions)
Operating Revenues:
Retail electric revenues	$	3,740		$	3,777		$	7,308		$	7,171
Wholesale electric revenues	611			618			1,230			1,149
Other electric revenues	175			167			339			342
Natural gas revenues (includes alternative revenue programs of $(4), $-, $(27), and $9, respectively)	706			684			2,314			2,214
Other revenues	395			184			808			326
Total operating revenues	5,627			5,430			11,999			11,202
Operating Expenses:
Fuel	1,103			1,092			2,204			2,088
Purchased power	236			211			503			390
Cost of natural gas	228			232			949			951
Cost of other sales	279			114			568			203
Other operations and maintenance	1,559			1,356			3,008			2,740
Depreciation and amortization	783			754			1,552			1,469
Taxes other than income taxes	316			308			671			638
Estimated loss on plants under construction	1,060			3,012			1,105			3,120
Total operating expenses	5,564			7,079			10,560			11,599
Operating Income (Loss)	63			(1,649		)	1,439			(397		)
Other Income and (Expense):
Allowance for equity funds used during construction	32			58			63			115
Earnings from equity method investments	31			28			72			67
Interest expense, net of amounts capitalized	(470		)	(424		)	(928		)	(840		)
Other income (expense), net	78			52			138			98
Total other income and (expense)	(329		)	(286		)	(655		)	(560		)
Earnings (Loss) Before Income Taxes	(266		)	(1,935		)	784			(957		)
Income taxes (benefit)	(139		)	(587		)	(25		)	(273		)
Consolidated Net Income (Loss)	(127		)	(1,348		)	809			(684		)
Dividends on preferred and preference stock of subsidiaries	4			11			8			22
Net income attributable to noncontrolling interests	23			22			17			17
Consolidated Net Income (Loss) Attributable to Southern Company	$	(154	)	$	(1,381	)	$	784		$	(723	)
Common Stock Data:
Earnings (loss) per share —
Basic	$	(0.15	)	$	(1.38	)	$	0.77		$	(0.73	)
Diluted	$	(0.15	)	$	(1.37	)	$	0.77		$	(0.72	)
Average number of shares of common stock outstanding (in millions)
Basic	1,014			998			1,012			996
Diluted	1,014			1,005			1,017			1,003
Cash dividends paid per share of common stock	$	0.60		$	0.58		$	1.18		$	1.14

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

11

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,
	2018			2017			2018			2017
	(in millions)						(in millions)
Consolidated Net Income (Loss)	$	(127	)	$	(1,348	)	$	809		$	(684	)
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(18), $23, $(3), and $17, respectively	(54		)	38			(8		)	29
Reclassification adjustment for amounts included in net income, net of tax of $21, $(25), $15, and $(26), respectively	64			(41		)	45			(42		)
Pension and other postretirement benefit plans:
Reclassification adjustment for amounts included in net income, net of tax of $1, $1, $1, and $1, respectively	2			1			4			2
Total other comprehensive income (loss)	12			(2		)	41			(11		)
Comprehensive Income (Loss)	(115		)	(1,350		)	850			(695		)
Dividends on preferred and preference stock of subsidiaries	4			11			8			22
Comprehensive income attributable to noncontrolling interests	23			22			17			17
Consolidated Comprehensive Income (Loss) Attributable to Southern Company	$	(142	)	$	(1,383	)	$	825		$	(734	)

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

12

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Six Months Ended June 30,
	2018			2017
	(in millions)
Operating Activities:
Consolidated net income (loss)	$	809		$	(684	)
Adjustments to reconcile consolidated net income (loss) to net cash provided from operating activities —
Depreciation and amortization, total	1,750			1,683
Deferred income taxes	(338		)	(270		)
Allowance for equity funds used during construction	(63		)	(115		)
Pension, postretirement, and other employee benefits	(74		)	(83		)
Settlement of asset retirement obligations	(97		)	(87		)
Stock based compensation expense	83			73
Estimated loss on plants under construction	1,088			3,120
Impairment charges	161			—
Other, net	5			(118		)
Changes in certain current assets and liabilities —
-Receivables	94			107
-Prepayments	(73		)	(61		)
-Natural gas for sale, net of temporary LIFO liquidation	295			223
-Other current assets	(40		)	(30		)
-Accounts payable	(406		)	(353		)
-Accrued taxes	213			(132		)
-Accrued compensation	(284		)	(331		)
-Retail fuel cost over recovery	10			(187		)
-Other current liabilities	125			(14		)
Net cash provided from operating activities	3,258			2,741
Investing Activities:
Business acquisitions, net of cash acquired	(64		)	(1,046		)
Property additions	(3,828		)	(3,398		)
Nuclear decommissioning trust fund purchases	(571		)	(388		)
Nuclear decommissioning trust fund sales	566			383
Dispositions	500			65
Cost of removal, net of salvage	(128		)	(128		)
Change in construction payables, net	49			(117		)
Investment in unconsolidated subsidiaries	(63		)	(116		)
Payments pursuant to LTSAs	(103		)	(132		)
Other investing activities	18			(6		)
Net cash used for investing activities	(3,624		)	(4,883		)
Financing Activities:
Increase in notes payable, net	1,442			30
Proceeds —
Long-term debt	1,100			2,958
Common stock	222			417
Short-term borrowings	1,650			1,004
Redemptions and repurchases —
Long-term debt	(3,379		)	(1,478		)
Preferred and preference stock	—			(150		)
Short-term borrowings	(550		)	—
Distributions to noncontrolling interests	(42		)	(40		)
Capital contributions from noncontrolling interests	1,210			73
Payment of common stock dividends	(1,194		)	(1,134		)
Other financing activities	(223		)	(75		)
Net cash provided from financing activities	236			1,605
Net Change in Cash, Cash Equivalents, and Restricted Cash	(130		)	(537		)
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	2,147			1,992
Cash, Cash Equivalents, and Restricted Cash at End of Period	$	2,017		$	1,455
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $35 and $55 capitalized for 2018 and 2017, respectively)	$	927		$	833
Income taxes, net	4			1
Noncash transactions — Accrued property additions at end of period	1,067			629

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

13

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

Assets	At June 30, 2018			At December 31, 2017
	(in millions)
Current Assets:
Cash and cash equivalents	$	1,980		$	2,130
Receivables —
Customer accounts receivable	1,728			1,806
Energy marketing receivables	451			607
Unbilled revenues	769			810
Under recovered fuel clause revenues	159			171
Other accounts and notes receivable	621			698
Accumulated provision for uncollectible accounts	(42		)	(44		)
Materials and supplies	1,397			1,438
Fossil fuel for generation	462			594
Natural gas for sale	292			595
Prepaid expenses	398			452
Other regulatory assets, current	528			604
Assets held for sale, current	2,704			12
Other current assets	172			199
Total current assets	11,619			10,072
Property, Plant, and Equipment:
In service	99,626			103,542
Less: Accumulated depreciation	30,255			31,457
Plant in service, net of depreciation	69,371			72,085
Nuclear fuel, at amortized cost	874			883
Construction work in progress	6,947			6,904
Total property, plant, and equipment	77,192			79,872
Other Property and Investments:
Goodwill	5,315			6,268
Equity investments in unconsolidated subsidiaries	1,546			1,513
Other intangible assets, net of amortization of $205 and $186 at June 30, 2018 and December 31, 2017, respectively	702			873
Nuclear decommissioning trusts, at fair value	1,829			1,832
Leveraged leases	788			775
Miscellaneous property and investments	247			249
Total other property and investments	10,427			11,510
Deferred Charges and Other Assets:
Deferred charges related to income taxes	789			825
Unamortized loss on reacquired debt	333			206
Other regulatory assets, deferred	6,302			6,943
Assets held for sale	4,618			—
Other deferred charges and assets	1,497			1,577
Total deferred charges and other assets	13,539			9,551
Total Assets	$	112,777		$	111,005

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

14

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholders' Equity	At June 30, 2018			At December 31, 2017
	(in millions)
Current Liabilities:
Securities due within one year	$	2,237		$	3,892
Notes payable	4,981			2,439
Energy marketing trade payables	485			546
Accounts payable	2,162			2,530
Customer deposits	488			542
Accrued taxes	544			636
Accrued interest	469			488
Accrued compensation	646			959
Asset retirement obligations, current	332			351
Other regulatory liabilities, current	508			337
Liabilities held for sale, current	706			—
Other current liabilities	808			874
Total current liabilities	14,366			13,594
Long-term Debt	42,483			44,462
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	5,934			6,842
Deferred credits related to income taxes	6,647			7,256
Accumulated deferred ITCs	2,360			2,267
Employee benefit obligations	2,009			2,256
Asset retirement obligations, deferred	5,836			4,473
Accrued environmental remediation	273			389
Other cost of removal obligations	2,364			2,684
Other regulatory liabilities, deferred	140			239
Liabilities held for sale	2,833			—
Other deferred credits and liabilities	516			691
Total deferred credits and other liabilities	28,912			27,097
Total Liabilities	85,761			85,153
Redeemable Preferred Stock of Subsidiaries	324			324
Stockholders' Equity:
Common Stockholders' Equity:
Common stock, par value $5 per share —
Authorized — 1.5 billion shares
Issued — 1.0 billion shares
Treasury — June 30, 2018: 1.0 million shares
— December 31, 2017: 0.9 million shares
Par value	5,066			5,038
Paid-in capital	10,303			10,469
Treasury, at cost	(39		)	(36		)
Retained earnings	8,494			8,885
Accumulated other comprehensive loss	(188		)	(189		)
Total Common Stockholders' Equity	23,636			24,167
Noncontrolling Interests	3,056			1,361
Total Stockholders' Equity	26,692			25,528
Total Liabilities and Stockholders' Equity	$	112,777		$	111,005

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

15

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

SECOND QUARTER 2018 vs. SECOND QUARTER 2017

AND

YEAR-TO-DATE 2018 vs. YEAR-TO-DATE 2017

OVERVIEW

Southern Company is a holding company that owns all of the common stock of the traditional electric operating companies and the parent entities of Southern Power and Southern Company Gas and owns other direct and indirect subsidiaries. Discussion of the results of operations is focused on the Southern Company system's primary businesses of electricity sales by the traditional electric operating companies and Southern Power and the distribution of natural gas by Southern Company Gas. The four traditional electric operating companies are vertically integrated utilities providing electric service in four Southeastern states. Southern Power develops, constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. During the second quarter 2018, Southern Power completed the sale of a 33% equity interest in a newly-formed limited partnership indirectly owning substantially all of its solar facilities. Southern Company Gas distributes natural gas through its natural gas distribution utilities in four states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations. Through June 30, 2018, Southern Company Gas had seven natural gas distribution utilities in seven states. Subsequent to June 30, 2018, Southern Company Gas completed sales of three of its natural gas distribution utilities. During the second quarter 2018, Southern Company Gas completed the sale of Pivotal Home Solutions. Southern Company's other business activities include providing energy technologies and services to electric utilities and large industrial, commercial, institutional, and municipal customers. Customer solutions include distributed generation systems, utility infrastructure solutions, and energy efficiency products and services. Other business activities also include investments in telecommunications, leveraged lease projects, and gas storage facilities. For additional information, see BUSINESS – "The Southern Company System – Traditional Electric Operating Companies," " – Southern Power," " – Southern Company Gas," and " – Other Businesses" in Item 1 of the Form 10-K. See FUTURE EARNINGS POTENTIAL and Note (J) to the Condensed Financial Statements herein for additional information regarding disposition activity.

On May 20, 2018, Southern Company entered into a stock purchase agreement with NextEra Energy to sell Gulf Power for an aggregate cash purchase price of $5.75 billion (less the amount of indebtedness assumed at closing, which is currently estimated at approximately $1.4 billion), subject to certain adjustments. The completion of the sale is subject to the satisfaction or waiver of certain closing conditions and is expected to occur in the first half of 2019. The ultimate outcome of this matter cannot be determined at this time. See Note (J) to the Condensed Financial Statements under "Southern Company's Sale of Gulf Power" herein for additional information.

Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Atlanta Gas Light, and Nicor Gas recently reached agreements with their respective state PSCs or other applicable state regulatory agencies relating to the regulatory impacts of the Tax Reform Legislation, which, for some companies, included capital structure adjustments expected to help mitigate the potential adverse impacts to certain of their credit metrics. See Note (B) to the Condensed Financial Statements under "Regulatory Matters" herein for additional information regarding state PSC or other regulatory agency actions related to the Tax Reform Legislation. Also see MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters" of Southern Company in Item 7 of the Form 10-K and FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" and Note (H) to the Condensed Financial Statements herein for information regarding the Tax Reform Legislation.

Southern Company continues to focus on several key performance indicators. These indicators include, but are not limited to, customer satisfaction, plant availability, electric and natural gas system reliability, execution of major construction projects, and earnings per share.

16

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Plant Vogtle Units 3 and 4 Status

In 2009, the Georgia PSC certified construction of Plant Vogtle Units 3 and 4 (with electric generating capacity of approximately 1,100 MWs each). In March 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. In December 2017, the Georgia PSC approved Georgia Power's recommendation to continue construction.

In the second quarter 2018, Georgia Power revised its base cost forecast and estimated contingency to complete construction and start-up of Plant Vogtle Units 3 and 4 to $8.0 billion and $0.4 billion, respectively, for a total project capital cost forecast of $8.4 billion (net of $1.7 billion received under the Guarantee Settlement Agreement and $188 million in Customer Refunds recognized as a regulatory liability in 2017). Although Georgia Power believes these incremental costs are reasonable and necessary to complete the project and the Georgia PSC has stated the $7.3 billion estimate included in the seventeenth VCM proceeding does not represent a cost cap, Georgia Power does not intend to seek rate recovery for the $0.7 billion increase in costs included in the revised base capital cost forecast, which will be filed with the Georgia PSC in the nineteenth VCM report on August 31, 2018. In connection with future VCM filings, Georgia Power may request the Georgia PSC to evaluate costs included in the revised construction contingency estimate for rate recovery as and when they are appropriately included in the base capital cost forecast. After considering the significant level of uncertainty that exists regarding the future recoverability of costs included in the construction contingency estimate since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in these future regulatory proceedings, Georgia Power has recorded a total pre-tax charge to income of $1.1 billion ($0.8 billion after tax) as of June 30, 2018.

As a result of the increase in the total project capital cost forecast and Georgia Power's decision not to seek rate recovery of the increase in the base capital costs, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction. The Vogtle Owners are expected to conduct these votes in the third quarter 2018.

If the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 do not vote to continue construction, the Vogtle Joint Ownership Agreements provide that the project will be cancelled, and construction will cease. In the event that fewer than 90% of the Vogtle Owners vote to continue construction, Georgia Power and the other Vogtle Owners will assess options for Plant Vogtle Units 3 and 4. If Plant Vogtle Units 3 and 4 were cancelled and Georgia Power was unable to recover costs it has incurred in connection with the project, Southern Company's results of operations, cash flow, and financial condition would be materially impacted. The ultimate outcome of this matter cannot be determined at this time.

Georgia Power's revised cost estimate reflects an expected in-service date of November 2021 for Unit 3 and November 2022 for Unit 4.

See FUTURE EARNINGS POTENTIAL – "Construction Program – Nuclear Construction" and ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" herein for additional information.

RESULTS OF OPERATIONS

Net Income (Loss)

Second Quarter 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$1,227	N/M	$1,507	N/M

N/M - Not meaningful

Consolidated net loss attributable to Southern Company was $(154) million ($(0.15) per share) for the second quarter 2018 compared to a net loss of $(1.4) billion ($(1.38) per share) for the corresponding period in 2017. The change was primarily due to charges of $3.01 billion ($2.12 billion after tax) in 2017 related to the Kemper IGCC at

17

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Mississippi Power, partially offset by a $1.1 billion ($0.8 billion after tax) charge in the second quarter 2018 for an estimated probable loss on Georgia Power's construction of Plant Vogtle Units 3 and 4. Also contributing to the change were lower federal income tax expense as a result of the Tax Reform Legislation and higher retail electric revenues due to warmer weather in the second quarter 2018 compared to the corresponding period in 2017, partially offset by increased operations and maintenance expenses and reductions in retail revenues related to the regulatory treatment of the Tax Reform Legislation impacts.

Consolidated net income attributable to Southern Company was $784 million ($0.77 per share) for year-to-date 2018 compared to a net loss of $(723) million ($(0.73) per share) for the corresponding period in 2017. The change was primarily due to charges of $3.12 billion ($2.18 billion after tax) in 2017 related to the Kemper IGCC at Mississippi Power, partially offset by a $1.1 billion ($0.8 billion after tax) charge in the second quarter 2018 for an estimated probable loss on Georgia Power's construction of Plant Vogtle Units 3 and 4. Also contributing to the change were lower federal income tax expense as a result of the Tax Reform Legislation and higher retail electric revenues due to colder weather in the first quarter 2018 and warmer weather in the second quarter 2018 compared to the corresponding periods in 2017, partially offset by increased operations and maintenance expenses and reductions in retail revenues related to the regulatory treatment of the Tax Reform Legislation impacts.

Retail Electric Revenues

Second Quarter 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$(37)	(1.0)	$137	1.9

In the second quarter 2018, retail electric revenues were $3.7 billion compared to $3.8 billion for the corresponding period in 2017. For year-to-date 2018, retail electric revenues were $7.3 billion compared to $7.2 billion for the corresponding period in 2017.

Details of the changes in retail electric revenues were as follows:

	Second Quarter 2018					Year-to-Date 2018
	(in millions)			(% change)		(in millions)			(% change)
Retail electric – prior year	$	3,777				$	7,171
Estimated change resulting from –
Rates and pricing	(141		)	(3.7	)	(245		)	(3.4	)
Sales growth (decline)	(5		)	(0.1	)	22			0.3
Weather	73			1.9		217			3.0
Fuel and other cost recovery	36			0.9		143			2.0
Retail electric – current year	$	3,740		(1.0	)%	$	7,308		1.9	%

Revenues associated with changes in rates and pricing decreased in the second quarter and year-to-date 2018 when compared to the corresponding periods in 2017 primarily due to revenues deferred as regulatory liabilities for future adjustments to customer billings related to the Tax Reform Legislation and a decrease in the recovery of Plant Vogtle Units 3 and 4 construction financing costs under the NCCR tariff at Georgia Power, also primarily related to the Tax Reform Legislation. Also contributing to the year-to-date 2018 decrease was the rate pricing effect of increased customer usage at Georgia Power. These decreases were partially offset by higher contributions from variable demand-driven pricing from commercial and industrial customers at Georgia Power.

See Note 3 to the financial statements of Southern Company under "Regulatory Matters – Alabama Power," " – Georgia Power – Rate Plans," and " – Gulf Power – Retail Base Rate Cases" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for additional information.

18

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Revenues attributable to changes in sales decreased in the second quarter 2018 when compared to the corresponding period in 2017. Weather-adjusted residential KWH sales were flat in the second quarter 2018, primarily due to customer growth, offset by decreased customer usage. Weather-adjusted commercial KWH sales decreased 0.2% in the second quarter 2018, primarily due to decreased customer usage, partially offset by customer growth. Industrial KWH sales increased 0.6% in the second quarter 2018, primarily in the primary metals and stone, clay, and glass sectors, partially offset by decreased sales in the paper sector.

Revenues attributable to changes in sales increased for year-to-date 2018 when compared to the corresponding period in 2017. Weather-adjusted residential KWH sales and weather-adjusted commercial KWH sales increased 0.6% and 0.5%, respectively, for year-to-date 2018, primarily due to customer growth, partially offset by decreased customer usage. Industrial KWH sales increased 1.6% for year-to-date 2018, primarily in the primary metals and stone, clay and glass sectors, partially offset by decreased sales in the paper sector.

Fuel and other cost recovery revenues increased $36 million and $143 million in the second quarter and year-to-date 2018, respectively, when compared to the corresponding periods in 2017 primarily due to higher energy sales resulting from colder weather in the first quarter 2018 and warmer weather in the second quarter 2018 compared to the corresponding periods in 2017. Electric rates for the traditional electric operating companies includeprovisions 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 Electric Revenues

Second Quarter 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$(7)	(1.1)	$81	7.0

Wholesale electric revenues consist of PPAs primarily with investor-owned utilities and electric cooperatives and short-term opportunity sales. Wholesale electric revenues from PPAs (other than solar and wind PPAs) have both capacity and energy components. Capacity revenues generally represent the greatest contribution to net income and are designed to provide recovery of fixed costs plus 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 electric 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. Energy sales from solar and wind PPAs do not have a capacity charge and customers either purchase the energy output of a dedicated renewable facility through an energy charge or through a fixed price related to the energy. As a result, Southern Company'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, transmission constraints, and other factors. Wholesale electric revenues at Mississippi Power include FERC-regulated municipal and rural association sales under cost-based tariffs 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.

For year-to-date 2018, wholesale electric revenues were $1.2 billion compared to $1.1 billion for the corresponding period in 2017. This increase was related to a $90 million increase in energy revenues, partially offset by a $9 million decrease in capacity revenues. The year-to-date 2018 increase in energy revenues primarily related to Southern Power and included an increase in fuel costs that are contractually recovered through PPAs, revenues from new natural gas PPAs from existing facilities, and an increase in sales from renewable facilities, partially offset by a decrease in non-PPA revenues from short-term sales.

19

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Natural Gas Revenues

Second Quarter 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$22	3.2	$100	4.5

In the second quarter 2018, natural gas revenues were $706 million compared to $684 million for the corresponding period in 2017. For year-to-date 2018, natural gas revenues were $2.3 billion compared to $2.2 billion for the corresponding period in 2017.

Details of the changes in natural gas revenues were as follows:

	Second Quarter 2018					Year-to-Date 2018
	(in millions)			(% change)		(in millions)			(% change)
Natural gas revenues – prior year	$	684				$	2,214
Estimated change resulting from –
Infrastructure replacement programs and base rate changes	38			5.6	%	48			2.2	%
Gas costs and other cost recovery	(4		)	(0.6	)%	(2		)	(0.1	)
Weather	8			1.2	%	16			0.7
Wholesale gas services	(4		)	(0.6	)%	31			1.4
Other	(16		)	(2.4	)%	7			0.3
Natural gas revenues – current year	$	706		3.2	%	$	2,314		4.5	%

The increases in natural gas revenues in the second quarter and year-to-date 2018 were primarily related to continued infrastructure investments recovered through replacement programs and base rate changes at the natural gas distribution utilities. These changes include base rate increases as a result of rate cases, partially offset by revenue reductions for the impacts of the Tax Reform Legislation.

Revenues attributable to gas costs and other cost recovery decreased due to reduced natural gas prices during 2018 compared to the corresponding periods in 2017, partially offset by increased volumes of natural gas sold in 2018 as a result of colder weather, as determined by Heating Degree Days.

Revenues increased due to colder weather, as determined by Heating Degree Days, in 2018 compared to the corresponding periods in 2017 that affected the utility customers in Illinois and Southern Company Gas' gas marketing services customers in Georgia and Illinois.

Revenues attributable to Southern Company Gas' wholesale gas services business decreased in the second quarter 2018 primarily due to derivative losses, partially offset by increased commercial activity and increased for year-to-date 2018 primarily due to increased commercial activity, partially offset by derivative losses.

Natural gas distribution rates include provisions to adjust billings for fluctuations in natural gas costs. Therefore, gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas and do not affect net income from gas distribution operations.

See Note (B) to the Condensed Financial Statements herein under "Regulatory Matters – Southern Company Gas" for additional information.

20

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Other Revenues

Second Quarter 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$211	114.7	$482	147.9

In the second quarter 2018, other revenues were $395 million compared to $184 million for the corresponding period in 2017. For year-to-date 2018, other revenues were $808 million compared to $326 million for the corresponding period in 2017. These increases were primarily due to PowerSecure's storm restoration services in Puerto Rico.

Fuel and Purchased Power Expenses

	Second Quarter 2018 vs. Second Quarter 2017			Year-to-Date 2018 vs. Year-to-Date 2017
	(change in millions)		(% change)	(change in millions)		(% change)
Fuel	$	11	1.0	$	116	5.6
Purchased power	25		11.8	113		29.0
Total fuel and purchased power expenses	$	36		$	229

In the second quarter 2018, total fuel and purchased power expenses were $1.34 billion compared to $1.30 billion for the corresponding period in 2017. The increase was primarily the result of an $87 million increase in the volume of KWHs generated and purchased, partially offset by an $80 million decrease in the average cost of fuel and purchased power.

For year-to-date 2018, total fuel and purchased power expenses were $2.7 billion compared to $2.5 billion for the corresponding period in 2017. The increase was primarily the result of a $234 million increase in the volume of KWHs generated and purchased, partially offset by a $34 million net decrease in the average cost of fuel and purchased power.

In addition, fuel expense increased $30 million in both the second quarter and year-to-date 2018 in accordance with an Alabama PSC accounting order authorizing the use of excess deferred income taxes to offset under recovered fuel costs.

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 – "Regulatory Matters – Fuel Cost Recovery" and " – Alabama Power – Accounting Order" 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.

21

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

	Second Quarter 2018	Second Quarter 2017	Year-to-Date 2018	Year-to-Date 2017
Total generation (in billions of KWHs)	49	49	97	92
Total purchased power (in billions of KWHs)	5	4	10	9
Sources of generation (percent) —
Gas	46	44	46	45
Coal	30	30	29	29
Nuclear	14	16	15	16
Hydro	3	3	3	3
Other	7	7	7	7
Cost of fuel, generated (in cents per net KWH)—
Gas	2.74	2.94	2.80	2.93
Coal	2.75	2.85	2.82	2.87
Nuclear	0.82	0.80	0.80	0.80
Average cost of fuel, generated (in cents per net KWH)(a)	2.44	2.51	2.47	2.51
Average cost of purchased power (in cents per net KWH)(b)	5.00	5.47	5.64	5.28

(a) Cost of fuel and average cost of fuel, generated excludes a $30 million adjustment associated with the Alabama PSC accounting order related to excess deferred income taxes.

(b) 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 2018, fuel expense was $1.10 billion compared to $1.09 billion for the corresponding period in 2017. The increase was primarily due to a 6.9% increase in the volume of KWHs generated by natural gas and a 1.7% increase in the volume of KWHs generated by coal, partially offset by a 6.8% decrease in the average cost of natural gas per KWH generated and a 3.5% decrease in the average cost of coal per KWH generated.

For year-to-date 2018, fuel expense was $2.2 billion compared to $2.1 billion for the corresponding period in 2017. The increase was primarily due to a 10.4% increase in the volume of KWHs generated by natural gas and a 5.9% increase in the volume of KWHs generated by coal, partially offset by a 4.4% decrease in the average cost of natural gas per KWH generated and a 1.7% decrease in the average cost of coal per KWH generated.

Purchased Power

In the second quarter 2018, purchased power expense was $236 million compared to $211 million for the corresponding period in 2017. The increase was primarily due to an 18.4% increase in the volume of KWHs purchased, partially offset by an 8.6% decrease in the average cost per KWH purchased.

For year-to-date 2018, purchased power expense was $503 million compared to $390 million for the corresponding period in 2017. The increase was primarily due to a 16.3% increase in the volume of KWHs purchased and a 6.8% increase in the average cost per KWH purchased.

Energy purchases will vary depending on demand for energy within the Southern Company system's electric 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.

22

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Cost of Other Sales

Second Quarter 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$165	144.7	$365	179.8

In the second quarter 2018, cost of other sales was $279 million compared to $114 million for the corresponding period in 2017. For year-to-date 2018, cost of other sales was $568 million compared to $203 million for the corresponding period in 2017. These increases primarily reflect costs related to PowerSecure's storm restoration services in Puerto Rico.

Other Operations and Maintenance Expenses

Second Quarter 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$203	15.0	$268	9.8

In the second quarter 2018, other operations and maintenance expenses were $1.6 billion compared to $1.4 billion for the corresponding period in 2017. The increase was primarily due to an asset impairment charge of $119 million at Southern Power related to the pending sale of its Florida plants, a $36 million loss on the sale of Pivotal Home Solutions at Southern Company Gas, and a $27 million increase in transmission and distribution costs, primarily related to line maintenance.

For year-to-date 2018, other operations and maintenance expenses were $3.0 billion compared to $2.7 billion for the corresponding period in 2017. The increase was primarily due to an asset impairment charge of $119 million at Southern Power related to the pending sale of its Florida plants, a $42 million goodwill impairment charge at Southern Company Gas related to the sale of Pivotal Home Solutions, and a $36 million loss on the sale of Pivotal Home Solutions at Southern Company Gas. Also contributing to the increase were a $38 million increase in transmission and distribution costs, primarily related to line maintenance, a $19 million decrease in gains from sales of integrated transmission system assets at Georgia Power, and a $12 million increase at Southern Company Gas to align paid time off with the Southern Company system's policy. These increases were partially offset by $32.5 million resulting from the write-down of Gulf Power's ownership of Plant Scherer Unit 3 in the first quarter 2017 in accordance with a settlement agreement approved by the Florida PSC in April 2017 (2017 Gulf Power Rate Case Settlement Agreement).

See Note (A) to the Condensed Financial Statements under "Goodwill and Other Intangible Assets" and Note (J) to the Condensed Financial Statements under "Southern Company Gas – Sale of Pivotal Home Solutions" and "Southern Power – Sale of Florida Plants" herein for additional information. Also see Note 3 to the financial statements of Southern Company under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" in Item 8 of the Form 10-K for additional information regarding the 2017 Gulf Power Rate Case Settlement Agreement.

Depreciation and Amortization

Second Quarter 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$29	3.8	$83	5.7

In the second quarter 2018, depreciation and amortization was $783 million compared to $754 million for the corresponding period in 2017. For year-to-date 2018, depreciation and amortization was $1.6 billion compared to $1.5 billion for the corresponding period in 2017. These increases primarily reflect increases of $31 million and $65 million for the second quarter and year-to-date 2018, respectively, related to additional plant in service.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Additionally, these increases were due to depreciation credits of $8.5 million and $34 million recognized in the second quarter and year-to-date 2017, respectively, as authorized in Gulf Power's 2013 rate case settlement.

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

Taxes Other Than Income Taxes

Second Quarter 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$8	2.6	$33	5.2

In the second quarter 2018, taxes other than income taxes were $316 million compared to $308 million for the corresponding period in 2017. For year-to-date 2018, taxes other than income taxes were $671 million compared to $638 million for the corresponding period in 2017. These increases were primarily due to increased property taxes at Georgia Power, increased revenue tax expenses at Southern Company Gas, and increased payroll taxes related to aligning paid time off at Southern Company Gas with the Southern Company system's policy. Also contributing to the year-to-date 2018 increase was an increase in municipal franchise fees primarily related to higher retail revenues at Georgia Power.

Estimated Loss on Plants Under Construction

Second Quarter 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$(1,952)	(64.8)	$(2,015)	(64.6)

In the second quarter 2018, estimated loss on plants under construction was $1.06 billion compared to $3.01 billion for the corresponding period in 2017. For year-to-date 2018, estimated loss on plants under construction was $1.11 billion compared to $3.12 billion for the corresponding period in 2017. These decreases were primarily related to revisions to the estimated construction costs for, and subsequent suspension of, the Kemper IGCC in June 2017 at Mississippi Power, partially offset by Georgia Power's revised estimate to complete construction and start-up of Plant Vogtle Units 3 and 4 in the second quarter 2018.

See Note 3 to the financial statements of Southern Company under "Kemper County Energy Facility" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Kemper County Energy Facility" and "Nuclear Construction" herein for additional information.

Allowance for Equity Funds Used During Construction

Second Quarter 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$(26)	(44.8)	$(52)	(45.2)

In the second quarter 2018, AFUDC equity was $32 million compared to $58 million in the corresponding period in 2017. For year-to-date 2018, AFUDC equity was $63 million compared to $115 million in the corresponding period in 2017. These decreases primarily resulted from Mississippi Power's suspension of the Kemper IGCC construction in June 2017, partially offset by increases in capital expenditures related to environmental and transmission projects at Alabama Power.

See Note 3 to the financial statements of Southern Company under "Kemper County Energy Facility" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Kemper County Energy Facility" herein for additional information.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Interest Expense, Net of Amounts Capitalized

Second Quarter 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$46	10.8	$88	10.5

In the second quarter 2018, interest expense, net of amounts capitalized was $470 million compared to $424 million in the corresponding period in 2017. For year-to-date 2018, interest expense, net of amounts capitalized was $928 million compared to $840 million in the corresponding period in 2017. These increases were largely due to an increase in average outstanding long-term debt, primarily at the parent company and Southern Company Gas.

See Note 6 to the financial statements of Southern Company in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements herein for additional information.

Other Income (Expense), Net

Second Quarter 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$26	50.0	$40	40.8

In the second quarter 2018, other income (expense), net was $78 million compared to $52 million for the corresponding period in 2017. For year-to-date 2018, other income (expense), net was $138 million compared to $98 million for the corresponding period in 2017. These increases were primarily due to the settlement of Mississippi Power's Deepwater Horizon claim in May 2018. The year-to-date 2018 increase was also due to a gain from the settlement of a contractor litigation claim at Southern Company Gas.

See Note (B) to the Condensed Financial Statements under "General Litigation Matters – Mississippi Power" and "Southern Company Gas – Atlanta Gas Light's Pipeline Replacement Program" herein for additional information.

Income Taxes (Benefit)

Second Quarter 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$448	N/M	$248	N/M

N/M - Not meaningful

In the second quarter 2018, income tax benefit was $139 million compared to an income tax benefit of $587 million for the corresponding period in 2017. For year-to-date 2018, income tax benefit was $25 million compared to an income tax benefit of $273 million for the corresponding period in 2017. These changes were primarily due to charges recorded in 2017 related to the Kemper IGCC at Mississippi Power, partially offset by the estimated probable loss on Plant Vogtle Units 3 and 4 at Georgia Power in the second quarter 2018 and lower federal income tax expense as well as the benefit from the flowback of excess deferred income taxes as a result of the Tax Reform Legislation. The year-to-date 2018 change was also due to net state income tax benefits arising from the reorganization of Southern Power's legal entities holding its solar facilities.

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

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Dividends on Preferred and Preference Stock of Subsidiaries

Second Quarter 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$(7)	(63.6)	$(14)	(63.6)

In the second quarter 2018, dividends on preferred and preference stock of subsidiaries was $4 million compared to $11 million for the corresponding period in 2017. For year-to-date 2018, dividends on preferred and preference stock of subsidiaries was $8 million compared to $22 million for the corresponding period in 2017. These decreases were primarily due to the 2017 redemptions of all outstanding shares of preferred and preference stock at Georgia Power and preference stock at Gulf Power.

See Note 6 the financial statements of Southern Company under "Redeemable Preferred Stock of Subsidiaries" 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 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 businesses of selling electricity and distributing natural gas. These factors include the traditional electric operating companies' and the natural gas distribution utilities' ability to maintain a constructive regulatory environment that allows for the timely recovery of prudently-incurred costs during a time of increasing costs and limited projected demand growth over the next several years. Plant Vogtle Units 3 and 4 construction and rate recovery and the profitability of Southern Power's competitive wholesale business and successful additional investments in renewable and other energy projects are also major factors.

Future earnings for the electricity and natural gas businesses will be driven primarily by customer growth. Earnings in the electricity business will also depend upon maintaining and growing sales, considering, among other things, the adoption and/or penetration rates of increasingly energy-efficient technologies, increasing volumes of electronic commerce transactions, and more multi-family home construction, all of which could contribute to a net reduction in customer usage. Earnings for both the electricity and natural gas businesses are subject to a variety of other 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 electric business also depends on numerous factors including regulatory matters, creditworthiness of customers, total electric generating capacity available and related costs, future acquisitions and construction of electric 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 the pace of economic growth that may be affected by changes in regional and global economic conditions, which may impact future earnings. In addition, the volatility of natural gas prices has a significant impact on the natural gas distribution utilities' customer rates, long-term competitive position against other energy sources, and the ability of Southern Company Gas' gas marketing services and wholesale gas 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 or businesses, 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.

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On May 20, 2018, Southern Company entered into a stock purchase agreement with NextEra Energy to sell of all of the capital stock of Gulf Power for an aggregate cash purchase price of $5.75 billion (less the amount of indebtedness assumed at closing, which is currently estimated at approximately $1.4 billion), subject to (i) customary adjustments for indebtedness and working capital and (ii) reduction by the amount (if any) by which Gulf Power fails to meet a specified capital expenditure target. The completion of the sale is subject to the satisfaction or waiver of certain closing conditions, including, among others, (i) the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act, (ii) approval by the FERC and the Federal Communications Commission, (iii) the entry into certain ancillary agreements, including transmission-related agreements and a transition services agreement, among the parties and their affiliates, and (iv) other customary closing conditions. Southern Company's sale of Gulf Power is expected to occur in the first half of 2019. See Note (J) to the Condensed Financial Statements under "Southern Company's Sale of Gulf Power" herein for additional information. The ultimate outcome of this matter cannot be determined at this time.

On June 4, 2018, Southern Company Gas completed the stock sale of Pivotal Home Solutions to American Water Enterprises LLC for a total cash purchase price of $358 million and an additional $6 million for working capital. This disposition resulted in a net loss of $76 million, which included $40 million of income tax expense. In contemplation of the transaction, a goodwill impairment charge of $42 million was recorded during the first quarter 2018.

On July 1, 2018, a Southern Company Gas subsidiary, Pivotal Utility Holdings, completed the sales of the assets of two of its natural gas distribution utilities, Elizabethtown Gas and Elkton Gas, to South Jersey Industries, Inc. for a total cash purchase price of $1.7 billion and an additional $40 million for working capital. This disposition resulted in an estimated pre-tax gain of approximately $235 million and an after-tax gain of approximately $12 million, which will be recorded in the third quarter 2018.

On July 29, 2018, Southern Company Gas and its wholly-owned direct subsidiary, NUI Corporation, completed the stock sale of Pivotal Utility Holdings, which primarily consisted of Florida City Gas, to NextEra Energy for a total cash purchase price of $530 million (less $3 million of indebtedness assumed at closing for customer deposits) and an additional $60 million for cash and other working capital. This disposition resulted in an estimated pre-tax gain of approximately $126 million and an after-tax gain of approximately $4 million, which will be recorded in the third quarter 2018.

The after-tax impacts of Southern Company Gas' dispositions included income tax expense on goodwill not deductible for tax purposes and for which a deferred tax liability had not been recorded previously. Additionally, each of these dispositions is subject to a final working capital adjustment that may impact the cash proceeds from disposition, but not the gain recorded. See Note (J) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information on Southern Company Gas' dispositions.

In May 2018, Southern Power completed the sale of a 33% equity interest in SPSH, a newly-formed limited partnership indirectly owning substantially all of Southern Power's solar facilities, for an aggregate purchase price of approximately $1.2 billion, subject to customary working capital adjustments. Southern Power maintains control and overall operational responsibilities for the solar facilities. See Note (J) to the Condensed Financial Statements under "Southern Power" herein for additional information.

Southern Power is pursuing the sale of a noncontrolling interest in a portfolio of eight operating wind facilities through the use of third-party tax equity, which, if successful, is expected to close in the fourth quarter 2018. See "Income Tax Matters – Southern Power" herein for additional information. 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.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Environmental Matters

The Southern Company system's operations are regulated by state and federal environmental agencies through a variety of laws and regulations governing air, water, land, and protection of other natural resources. The Southern Company system maintains comprehensive environmental compliance and greenhouse gas (GHG) strategies to assess upcoming requirements and compliance costs associated with these environmental laws and regulations. The costs, including capital expenditures and operations and maintenance costs, required to comply with environmental laws and regulations and to achieve stated goals may impact future unit retirement and replacement decisions, results of operations, cash flows, and financial condition. Related costs may result from the installation of additional environmental controls, closure and monitoring of CCR facilities, unit retirements, and adding or changing fuel sources for certain existing units, as well as related upgrades to the transmission system. A major portion of these costs are expected to be recovered through existing ratemaking provisions. The ultimate impact of environmental laws and regulations and the GHG goals discussed below will depend on various factors, such as state adoption and implementation of requirements, the availability and cost of any deployed control technology, and the outcome of pending and/or future legal challenges.

New or revised environmental laws and regulations could affect many areas of the traditional electric operating companies', Southern Power's, and the natural gas distribution utilities' operations. The impact of any such changes cannot be determined at this time. Environmental compliance costs could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis for the traditional electric operating companies and the natural gas distribution utilities or through long-term wholesale agreements for the traditional electric operating companies and Southern Power. Further, increased costs that are recovered through regulated rates could contribute to reduced demand for electricity and natural gas, which could negatively affect results of operations, cash flows, and financial condition. Additionally, many commercial and industrial customers may also be affected by existing and future environmental requirements, which for some may have the potential to ultimately affect their demand for electricity and natural gas. 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 Laws and Regulations

Water Quality

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Water Quality" of Southern Company in Item 7 of the Form 10-K for additional information regarding the effluent limitations guidelines (ELG) rule.

On May 2, 2018, the EPA updated its anticipated final rulemaking schedule for ELG from September 2020 to December 2019. The impact of any changes to the ELG rule will depend on the content of the final rule and the outcome of 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 Laws and Regulations – Coal Combustion Residuals" of Southern Company in Item 7 of the Form 10-K for additional information regarding the Disposal of Coal Combustion Residuals from Electric Utilities rule (CCR Rule).

On July 30, 2018, the EPA published certain amendments to the CCR Rule, which will be effective August 29, 2018. These amendments extend the date from April 2019 to October 31, 2020 to cease sending CCR and other waste streams to impoundments that demonstrate compliance with all except two specified criteria. These amendments also establish groundwater protection standards for four constituents that do not have established EPA maximum contaminant levels and allow a participating state director or the EPA (where the EPA is the permitting authority) to suspend groundwater monitoring requirements under certain circumstances. Specific site impacts are being evaluated by the traditional electric operating companies.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

In June 2018, Alabama Power recorded an increase of approximately $1.2 billion to its AROs related to the CCR Rule. The revised cost estimates as of June 30, 2018 are based on information from feasibility studies performed on ash ponds in use at plants operated by Alabama Power, including a plant jointly-owned by Mississippi Power. During the second quarter 2018, Alabama Power's management completed its analysis of these studies which indicated that additional closure costs, primarily related to increases in estimated ash volume, water management requirements, and design revisions, will be required to close these ash ponds under the planned closure-in-place methodology.

Georgia Power continues to perform engineering studies related to its plans to close the ash ponds at all of its generating plants, including one jointly owned with Gulf Power, in compliance with federal and state CCR rules. Georgia Power also continues to refine its closure strategy and cost estimates for each ash pond and is preparing permit applications as required by the State of Georgia CCR rule. While Georgia Power believes its recorded liability for ash pond closures appropriately reflects its obligations under the current closure strategies it has elected, changes to such strategies and cost estimates would likely result in additional closure costs which would increase Georgia Power's ARO liability. It is not currently possible to determine the magnitude of an increase related to a change in closure strategies nor an increase related to ongoing engineering studies for the current closure strategies, and the timing of future cash outflows are indeterminable at this time. As permit applications advance, engineering studies continue, and the timing of ash pond closures develop further on a plant-by-plant basis during the second half of 2018 and in the future, Georgia Power will record any changes as necessary to its ARO liability, which could be material. Georgia Power expects to continue to periodically update these cost estimates as necessary, which could change further as additional information becomes available.

As further analysis is performed and closure details are developed with respect to ash pond closures, the traditional electric operating companies expect to periodically update their cost estimates as necessary. Absent continued recovery of ARO costs through regulated rates, Southern Company's results of operations, cash flows, and financial condition could be materially impacted. See Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information.

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

Nuclear Decommissioning

In June 2018, Alabama Power completed an updated decommissioning cost site study for Plant Farley. The estimated cost of decommissioning based on the study resulted in an increase in the ARO liability of approximately $300 million. Amounts previously contributed to Alabama Power's external trust funds are currently projected to be adequate to meet the updated decommissioning obligations. See Note 1 to the financial statements of Southern Company under "Nuclear Decommissioning" in Item 8 of the Form 10-K and Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" and "Nuclear Decommissioning" herein for additional information.

Global Climate Issues

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues" of Southern Company in Item 7 of the Form 10-K for additional information regarding domestic GHG policies.

Through 2017, the Southern Company system has achieved an estimated GHG emission reduction of 36% since 2007. In April 2018, Southern Company established an intermediate goal of a 50% reduction in carbon emissions from 2007 levels by 2030 and a long-term goal of low- to no-carbon operations by 2050. To achieve these goals, the Southern Company system expects to continue growing its renewable energy portfolio, optimize technology advancements to modernize its transmission and distribution systems, increase the use of natural gas for generation, complete construction of Plant Vogtle Units 3 and 4, invest in energy efficiency, and continue research and development efforts focused on technologies to lower GHG emissions. The Southern Company system's ability to achieve these goals also will be dependent on many external factors, including supportive national energy policies,

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low natural gas prices, and the development, deployment, and advancement of relevant energy technologies. The ultimate outcome of this matter cannot be determined at this time.

FERC Matters

Market-Based Rate Authority

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters – Market-Based Rate Authority" of Southern Company in Item 7 of the Form 10-K for additional information regarding proceedings related to the traditional electric operating companies'and Southern Power's 2014 and 2017 triennial market power analyses.

On May 4, 2018, the FERC issued an order terminating both proceedings, finding that the traditional electric operating companiesand Southern Power satisfy the FERC's standards for market-based rates. On May 9, 2018, the traditional electric operating companiesand Southern Power made the compliance filing required by the order. These proceedings are essentially concluded.

Open Access Transmission Tariff

On May 10, 2018, the Alabama Municipal Electric Authority and Cooperative Energy filed with the FERC a complaint against SCS and the traditional electric operating companiesclaiming that the current 11.25% base ROE used in calculating the annual transmission revenue requirements of the traditional electric operating companies'open access transmission tariff is unjust and unreasonable as measured by the applicable FERC standards. The complaint requests that the base ROE be set no higher than 8.65% and that the FERC order refunds for the difference in revenue requirements that results from applying a just and reasonable ROE established in this proceeding upon determining the current ROE is unjust and unreasonable. On June 18, 2018, SCS and the traditional electric operating companiesfiled their response challenging the adequacy of the showing presented by the complainants and offering support for the current ROE. The ultimate outcome of this matter cannot be determined at this time.

Regulatory Matters

Fuel Cost Recovery

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Fuel Cost Recovery" of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under "Regulatory Matters – Alabama Power – Rate ECR" and "Regulatory Matters – Georgia Power – Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information regarding fuel cost recovery for the traditional electric operating companies.

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 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.

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 Rate RSE, Rate CNP, Rate ECR, and Rate NDR. 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 "Regulatory Matters – Alabama Power" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for additional information regarding Alabama Power's rate mechanisms, accounting orders, and the recovery balance of each regulatory clause for Alabama Power.

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On May 1, 2018, the Alabama PSC approved modifications to Rate RSE and other commitments designed to position Alabama Power to address the growing pressure on its credit quality resulting from the Tax Reform Legislation, without increasing retail rates under Rate RSE in the near term. Alabama Power plans to reduce growth in total debt by increasing equity, with corresponding reductions in debt issuances, thereby de-leveraging its capital structure. Alabama Power's goal is to achieve an equity ratio of approximately 55% by the end of 2025. At June 30, 2018, Alabama Power's equity ratio was approximately 46.6%. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Federal Tax Reform Legislation" of Southern Company in Item 7 of the Form 10-K for additional information.

Rate RSE

The approved modifications to Rate RSE became effective June 2018 and are applicable for January 2019 billings and thereafter. The modifications include reducing the top of the allowed weighted common equity return (WCER) range from 6.21% to 6.15% and modifications to the refund mechanism applicable to prior year actual results. The modifications to the refund mechanism allow Alabama Power to retain a portion of the revenue that causes the actual WCER for a given year to exceed the allowed range.

In conjunction with these modifications to Rate RSE, on May 8, 2018, Alabama Power consented to a moratorium on any upward adjustments under Rate RSE for 2019 and 2020. Additionally, Alabama Power will return $50 million to customers through bill credits in 2019.

In accordance with an established retail tariff that provides for an interim adjustment to customer billings to recognize the impact of a change in the statutory income tax rate, Alabama Power is returning approximately $257 million to retail customers through bill credits in the second half of 2018 as a result of the change in the federal income tax rate under the Tax Reform Legislation.

Rate ECR

On May 1, 2018, the Alabama PSC approved an increase to Rate ECR from 2.015 cents per KWH to 2.353 cents per KWH effective July 2018 which is expected to result in additional collections of approximately $100 million through December 31, 2018. The approved increase in the Rate ECR factor will have no significant effect on Southern Company's net income, but will increase operating cash flows related to fuel cost recovery in 2018. The rate will return to 5.910 cents per KWH in 2019, absent a further order from the Alabama PSC.

Accounting Order

On May 1, 2018, the Alabama PSC approved an accounting order that authorizes Alabama Power to defer the benefits of federal excess deferred income taxes associated with the Tax Reform Legislation for the year ending December 31, 2018 as a regulatory liability and to use up to $30 million of such deferrals to offset under recovered amounts under Rate ECR. Any remaining amounts will be used for the benefit of customers as determined by the Alabama PSC. As of June 30, 2018, Alabama Power had applied approximately $30 million of such deferrals to offset the under recovered balance under Rate ECR and expects the total deferrals for the year ending December 31, 2018 to be approximately $50 million. See Note 5 to the financial statements of Southern Company under "Federal Tax Reform Legislation" in Item 8 of the Form 10-K for additional information.

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 certified construction costs of Plant Vogtle Units 3 and 4 are being collected through the NCCR tariff and fuel costs are collected through a separate fuel cost recovery tariff. See Note (B) to the Condensed Financial Statements under "Nuclear Construction" herein and Note 3 to the financial statements of Southern Company under "Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding Georgia Power's NCCR

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tariff. Also see Note (B) to the Condensed Financial Statements under "Regulatory Matters – Georgia Power – Fuel Cost Recovery" herein for additional information regarding Georgia Power's fuel cost recovery.

Rate Plans

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Georgia Power – Rate Plans" of Southern Company in Item 7 of the Form 10-K for additional information regarding Georgia Power's 2013 ARP and the Georgia PSC's 2018 order related to the Tax Reform Legislation.

On April 3, 2018, the Georgia PSC approved a settlement agreement between Georgia Power and the staff of the Georgia PSC regarding the retail rate impact of the Tax Reform Legislation (Georgia Power Tax Reform Settlement Agreement). Pursuant to the Georgia Power Tax Reform Settlement Agreement, to reflect the federal income tax rate reduction impact of the Tax Reform Legislation, Georgia Power will refund to customers a total of $330 million through bill credits of $131 million in October 2018, $96 million in June 2019, and $103 million in February 2020. In addition, Georgia Power is deferring as a regulatory liability (i) the revenue equivalent of the tax expense reduction resulting from legislation lowering the Georgia state income tax rate from 6.00% to 5.75% in 2019 and (ii) the entire benefit of approximately $700 million in federal and state excess accumulated deferred income taxes. The amortization of these regulatory liabilities is expected to be addressed in Georgia Power's next base rate case, which is scheduled to be filed by July 1, 2019. If there is not a base rate case in 2019, customers will receive $185 million in annual bill credits beginning in 2020, with any additional federal and state income tax savings deferred as a regulatory liability, until Georgia Power's next base rate case.

To address the negative cash flow and credit metric impacts of the Tax Reform Legislation, the Georgia PSC also approved an increase in Georgia Power's retail equity ratio to the lower of (i) Georgia Power's actual common equity weight in its capital structure or (ii) 55%, until Georgia Power's next base rate case. Benefits from reduced federal income tax rates in excess of the amounts refunded to customers will be retained by Georgia Power to cover the carrying costs of the incremental equity in 2018 and 2019.

Gulf Power

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

As a continuation of the 2017 Gulf Power Rate Case Settlement Agreement, on March 26, 2018, the Florida PSC approved a stipulation and settlement agreement among Gulf Power and three intervenors addressing the retail revenue requirement effects of the Tax Reform Legislation (Gulf Power Tax Reform Settlement Agreement).

The Gulf Power Tax Reform Settlement Agreement results in annual reductions to Gulf Power's revenues of $18.2 million from base rates and $15.6 million from environmental cost recovery rates, implemented April 1, 2018, and also provides for a one-time refund of $69.4 million for the retail portion of unprotected (not subject to normalization) deferred tax liabilities through a reduced fuel cost recovery rate over the remainder of 2018. Through June 30, 2018, approximately $28 million of this refund has been reflected in customer bills. As a result of the Gulf Power Tax Reform Settlement Agreement, the Florida PSC also approved an increase in Gulf Power's maximum equity ratio from 52.5% to 53.5% for all retail regulatory purposes.

As part of the Gulf Power Tax Reform Settlement Agreement, a limited scope proceeding to address protected deferred tax liabilities consistent with IRS normalization principles was initiated on April 30, 2018. Pending resolution of this proceeding, Gulf Power is deferring the related amounts for 2018 as a regulatory liability. Through June 30, 2018, amounts deferred totaled $5 million. Unless otherwise agreed to by the parties to the Gulf Power Tax Reform Settlement Agreement, amounts recorded in this regulatory liability will be refunded to retail customers in 2019 through Gulf Power's fuel cost recovery rates. The ultimate outcome of this matter cannot be determined at this time.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Mississippi Power

On February 7, 2018, Mississippi Power submitted its revised 2018 projected PEP filing to the Mississippi PSC, which reflected the impacts of the Tax Reform Legislation, requesting an increase in annual retail revenues of $26 million based on a performance adjusted ROE of 9.33% and an increased equity ratio of 55%.

On July 27, 2018, Mississippi Power and the Mississippi Public Utilities Staff (MPUS) entered into a settlement agreement with respect to the 2018 PEP filing and all unresolved PEP filings for prior years (PEP Settlement Agreement), which was approved by the Mississippi PSC on August 7, 2018. Rates under the PEP Settlement Agreement will take effect for the first billing cycle of September 2018.

The PEP Settlement Agreement provides for an increase of approximately $21.6 million in annual base retail revenues, which excludes approximately $5.5 million requested for certain compensation costs contested by the MPUS. Under the PEP Settlement Agreement, Mississippi Power expects to defer these costs for 2018 and 2019 as a regulatory asset. The Mississippi PSC is currently expected to rule on the appropriate treatment for such costs in connection with Mississippi Power's next base rate case, which is scheduled to be filed in the fourth quarter 2019 (2019 Base Rate Case). The ultimate outcome of this matter cannot be determined at this time.

Pursuant to the PEP Settlement Agreement, Mississippi Power's performance-adjusted allowed ROE will be 9.31% and its allowed equity ratio will remain at 50%, pending further review by the Mississippi PSC. In lieu of the requested equity ratio increase, Mississippi Power will retain $44 million of excess accumulated deferred income taxes resulting from the Tax Reform Legislation, which had been proposed to be amortized beginning in 2018, until the conclusion of the 2019 Base Rate Case. Further, Mississippi Power will seek equity contributions sufficient to restore its equity ratio (which was 43.5% at June 30, 2018) to the 50% target. In the event Mississippi Power's actual average equity ratio for 2018 is more than 1% higher or lower than the 50% target, Mississippi Power will defer the corresponding difference in its revenue requirement as a regulatory asset or liability for resolution in the 2019 Base Rate Case.

Pursuant to the PEP Settlement Agreement, PEP proceedings will be suspended until after the conclusion of the 2019 Base Rate Case and Mississippi Power will not be required to make any PEP filings for regulatory years 2018, 2019, and 2020. The PEP Settlement Agreement also resolves all open PEP filings with no change to customer rates. As a result, in the third quarter 2018, Mississippi Power expects to recognize revenues of $5 million previously reserved in connection with the 2012 PEP lookback filing.

Southern Company Gas

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Southern Company Gas" of Southern Company in Item 7 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Southern Company Gas" herein for additional information.

On February 23, 2018, Atlanta Gas Light revised its annual base rate filing to reflect the impacts of the Tax Reform Legislation and requested a $16 million rate reduction in 2018. On May 15, 2018, the Georgia PSC approved a stipulation for Atlanta Gas Light's annual base rates to remain at the 2017 level for 2018 and 2019, with customer credits of $8 million in each of July 2018 and October 2018 to reflect the impacts of the Tax Reform Legislation. The Georgia PSC maintained Atlanta Gas Light's previously authorized earnings band based on a ROE between 10.55% and 10.95% and increased the allowed equity ratio by 4% to an equity ratio of 55% to address the negative cash flow and credit metric impacts of the Tax Reform Legislation. Additionally, Atlanta Gas Light is required to file a traditional base rate case on or before June 1, 2019 for rates effective January 1, 2020.

On May 2, 2018, the Illinois Commission approved Nicor Gas' rehearing request for revised base rates to incorporate the reduction in the federal income tax rate as a result of the Tax Reform Legislation. The resulting decrease of approximately $44 million in annual base rate revenues became effective May 5, 2018. Nicor Gas' previously-authorized capital structure and ROE of 9.8% were not addressed in the rehearing and remain unchanged.

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Kemper County Energy Facility

For additional information on the Kemper County energy facility, see Note 3 to the financial statements of Southern Company under "Kemper County Energy Facility" in Item 8 of the Form 10-K.

As the mining permit holder for the Kemper County energy facility, Liberty Fuels Company, LLC has a legal obligation to perform mine reclamation, and Mississippi Power has a contractual obligation to fund all reclamation activities. Mine reclamation began in the first quarter 2018.

As of June 30, 2018, Mississippi Power recorded charges to income of an immaterial amount for the second quarter 2018 and $45 million ($33 million after tax) for year-to-date 2018, primarily resulting from the abandonment and related closure activities for the mine and gasifier-related assets at the Kemper County energy facility. Additional closure costs for the mine and gasifier-related assets, currently estimated to cost up to $25 million pre-tax (excluding salvage, net of dismantlement costs), are expected to be incurred during the remainder of 2018 and 2019. In addition, period costs, including, but not limited to, costs for compliance and safety, ARO accretion, and property taxes for the mine and gasifier-related assets, are estimated at $4 million for the remainder of 2018, $7 million in 2019, and $4 million annually beginning in 2020. The ultimate outcome of this matter cannot be determined at this time.

The combined cycle and associated common facilities portions of the Kemper County energy facility were dedicated as Plant Ratcliffe on April 27, 2018.

Reserve Margin Plan

On August 6, 2018, Mississippi Power filed its proposed Reserve Margin Plan (RMP), as required by the Mississippi PSC's order in the docket established for the purposes of pursuing a global settlement of the costs related to the Kemper County energy facility. Under the RMP, Mississippi Power proposes alternatives that would reduce its reserve margin, with the most economic of the alternatives being the2-year and 7-year acceleration of the retirement of Plant Watson Units 4 and 5, respectively, to the first quarter 2022 and the 4-year acceleration of the retirement of Plant Greene County Units 1 and 2 to the third quarter 2021 and the third quarter 2022, respectively, in order to lower or avoid operating costs. The Plant Greene County unit retirements would require the completion by Alabama Power of proposed transmission and system reliability improvements, as well as agreement by Alabama Power. The RMP filing also states that, in the event the Mississippi PSC ultimately approves an alternative that includes an accelerated retirement, Mississippi Power would require authorization to defer in a regulatory asset for future recovery the remaining net book value of the units at the time of retirement. Mississippi Power expects the MPUS and other interested parties to review the proposal prior to resolution by the Mississippi PSC. The ultimate outcome of this matter cannot be determined at this time. However, if approved by the Mississippi PSC, the alternatives are not expected to have any adverse impact on customer rates.

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 electric generating facilities, adding environmental modifications to certain existing units, expanding the electric transmission and distribution systems, and updating and expanding the natural gas 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 improvement programs designed to update or expand the natural gas distribution systems of the natural gas distribution utilities to improve reliability and meet operational flexibility and growth. The natural gas distribution utilities recover their investment and a return associated with these infrastructure programs through their regulated rates. See Notes 3 and 12 to the financial statements of Southern Company under "Regulatory Matters – Southern Company Gas – Regulatory

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Infrastructure Programs" and "Southern Power – Construction Projects in Progress," respectively, in Item 8 of the Form 10-K and Note (J) to the Condensed Financial Statements under "Southern Power" herein for additional information.

The largest construction project currently underway in the Southern Company system is Plant Vogtle Units 3 and 4 (45.7% ownership interest by Georgia Power in the two units, each with approximately 1,100 MWs). See Note 3 to the financial statements of Southern Company under "Nuclear Construction" in Item 8 of the Form 10-K and "Nuclear Construction" herein for additional information.

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.

Nuclear Construction

See Note 3 to the financial statements of Southern Company under "Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding the construction of Plant Vogtle Units 3 and 4, VCM reports, and the NCCR tariff.

In 2009, the Georgia PSC certified construction of Plant Vogtle Units 3 and 4. In 2012, the NRC issued the related combined construction and operating licenses, which allowed full construction of the two AP1000 nuclear units (with electric generating capacity of approximately 1,100 MWs each) and related facilities to begin. Until March 2017, construction on Plant Vogtle Units 3 and 4 continued under the Vogtle 3 and 4 Agreement, which was a substantially fixed price agreement. In March 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code.

In connection with the EPC Contractor's bankruptcy filing, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into the Interim Assessment Agreement with the EPC Contractor to allow construction to continue. The Interim Assessment Agreement expired in July 2017 when Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the EPC Contractor entered into the Vogtle Services Agreement. Under the Vogtle Services Agreement, Westinghouse provides facility design and engineering services, procurement and technical support, and staff augmentation on a time and materials cost basis. The Vogtle Services Agreement will continue until the start-up and testing of Plant Vogtle Units 3 and 4 are complete and electricity is generated and sold from both units. The Vogtle Services Agreement is terminable by the Vogtle Owners upon 30 days' written notice.

In October 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into a construction completion agreement with Bechtel, whereby Bechtel will serve as the primary contractor for the remaining construction activities for Plant Vogtle Units 3 and 4 (Bechtel Agreement). The Bechtel Agreement is a cost reimbursable plus fee arrangement, whereby Bechtel is reimbursed for actual costs plus a base fee and an at-risk fee, which is subject to adjustment based on Bechtel's performance against cost and schedule targets. Each Vogtle Owner is severally (not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to Bechtel under the Bechtel Agreement. The Vogtle Owners may terminate the Bechtel Agreement at any time for their convenience, provided that the Vogtle Owners will be required to pay amounts related to work performed prior to the termination (including the applicable portion of the base fee), certain termination-related costs, and, at certain stages of the work, the applicable portion of the at-risk fee. Bechtel may terminate the Bechtel Agreement under certain circumstances, including certain Vogtle Owner suspensions of work, certain breaches of the Bechtel Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events. Pursuant to the Loan Guarantee Agreement between Georgia Power and the DOE, Georgia Power is required to obtain the DOE's approval of the Bechtel Agreement prior to obtaining any further advances under the Loan Guarantee Agreement.

In December 2017, the Georgia PSC approved Georgia Power's seventeenth VCM report, which included a recommendation to continue construction of Plant Vogtle Units 3 and 4, with Southern Nuclear serving as project manager and Bechtel serving as the primary construction contractor.

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Cost and Schedule

In preparation for its nineteenth VCM filing, Georgia Power requested Southern Nuclear to perform a full cost reforecast for the project. Georgia Power's approximate proportionate share of the remaining estimated capital cost to complete Plant Vogtle Units 3 and 4 by the expected in-service dates of November 2021 and November 2022, respectively, is as follows:

	(in billions)
Base project capital cost forecast(a)(b)	$	8.0
Construction contingency estimate	0.4
Total project capital cost forecast(a)(b)	8.4
Net investment as of June 30, 2018(b)	(4.0		)
Remaining estimate to complete(a)	$	4.4

(a) Excludes financing costs expected to be capitalized through AFUDC of approximately $350 million.

(b) Net of $1.7 billion received from Toshiba in 2017 under the Guarantee Settlement Agreement and $188 million in Customer Refunds recognized as a regulatory liability in 2017.

Georgia Power estimates that its financing costs for construction of Plant Vogtle Units 3 and 4 will total approximately $3.2 billion, of which $1.7 billion had been incurred through June 30, 2018.

The $0.7 billion increase to the base capital cost forecast reflected in the table above primarily results from changed assumptions related to the finalization of contract scopes and management responsibilities for Bechtel and over 60 subcontractors, labor productivity rates, and craft labor incentives, as well as the related levels of project management, oversight, and support, including field supervision and engineering support.

Although Georgia Power believes these incremental costs are reasonable and necessary to complete the project and the Georgia PSC's order in the seventeenth VCM proceeding specifically states that the construction of Plant Vogtle Units 3 and 4 is not subject to a cost cap, Georgia Power does not intend to seek rate recovery for these cost increases included in the current base capital cost forecast (or any related financing costs), which will be filed with the Georgia PSC in the nineteenth VCM report at the end of August 2018. In connection with future VCM filings, Georgia Power may request the Georgia PSC to evaluate costs currently included in the construction contingency estimate for rate recovery as and when they are appropriately included in the base capital cost forecast. After considering the significant level of uncertainty that exists regarding the future recoverability of costs included in the construction contingency estimate since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in these future regulatory proceedings, Georgia Power has recorded a total pre-tax charge to income of $1.1 billion ($0.8 billion after tax), which includes the total increase in the capital cost forecast and construction contingency estimate as of June 30, 2018.

Subsequent to the EPC Contractor bankruptcy filing, a number of subcontractors to the EPC Contractor alleged non-payment by the EPC Contractor for amounts owed for work performed on Plant Vogtle Units 3 and 4. Georgia Power, acting for itself and as agent for the Vogtle Owners, has taken actions to remove liens filed by these subcontractors through the posting of surety bonds. Related to such liens, certain subcontractors have filed, and additional subcontractors may file, lawsuits against the EPC Contractor and the Vogtle Owners to preserve their payment rights with respect to such claims. All known amounts associated with the removal of subcontractor liens and other EPC Contractor pre-petition accounts payable have been paid or accrued as of June 30, 2018. The ultimate liability is expected to be finalized in connection with the completion of the sale of Westinghouse.

As construction continues, challenges with management of contractors, subcontractors, and vendors; labor productivity, availability, and/or cost escalation; procurement, fabrication, delivery, assembly, and/or installation, including any required engineering changes, of plant systems, structures, and components (some of which are based on new technology that is just beginning initial operation in the global nuclear industry at this scale); or other issues could arise and change the projected schedule and estimated cost.

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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. 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, 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.

The ultimate outcome of these matters cannot be determined at this time. However, any extension of the project schedule is currently estimated to result in additional base capital costs of approximately $50 million per month, based on Georgia Power's ownership interests, and AFUDC of approximately $12 million per month. While Georgia Power is not precluded from seeking recovery of any future capital cost forecast increase, management will ultimately determine whether or not to seek recovery. Any further changes to the capital cost forecast that are not expected to be recoverable through regulated rates will be required to be charged to income and such charges could be material.

Joint Owner Contracts

In November 2017, the Vogtle Owners entered into an amendment to their joint ownership agreements for Plant Vogtle Units 3 and 4 (as amended, Vogtle Joint Ownership Agreements) to provide for, among other conditions, additional Vogtle Owner approval requirements. Pursuant to the Vogtle Joint Ownership Agreements, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction if certain adverse events occur, including: (i) the bankruptcy of Toshiba; (ii) termination or rejection in bankruptcy of certain agreements, including the Vogtle Services Agreement or the Bechtel Agreement; (iii) the Georgia PSC or Georgia Power determines that any of Georgia Power's costs relating to the construction of Plant Vogtle Units 3 and 4 will not be recovered in retail rates because such costs are deemed unreasonable or imprudent; or (iv) an increase in the construction budget contained in the seventeenth VCM report of more than $1 billion or extension of the project schedule contained in the seventeenth VCM report of more than one year. In addition, pursuant to the Vogtle Joint Ownership Agreements, the required approval of holders of ownership interests in Plant Vogtle Units 3 and 4 is at least (i) 90% for a change of the primary construction contractor and (ii) 67% for material amendments to the Vogtle Services Agreement or agreements with Southern Nuclear or the primary construction contractor, including the Bechtel Agreement. The Vogtle Joint Ownership Agreements also confirm that the Vogtle Owners' sole recourse against Georgia Power or Southern Nuclear for any action or inaction in connection with their performance as agent for the Vogtle Owners is limited to removal of Georgia Power and/or Southern Nuclear as agent, except in cases of willful misconduct.

As a result of the increase in the total project capital cost forecast and Georgia Power's decision not to seek rate recovery of the increase in the base capital costs as described in "Cost and Schedule" herein, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction. The Vogtle Owners are expected to conduct these votes in the third quarter 2018.

If the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 do not vote to continue construction, the Vogtle Joint Ownership Agreements provide that the project will be cancelled, and construction will cease. In the event that fewer than 90% of the Vogtle Owners vote to continue construction, Georgia Power and the other Vogtle Owners will assess options for Plant Vogtle Units 3 and 4. If Plant Vogtle Units 3 and 4 were cancelled and Georgia Power was unable to recover costs it has incurred in connection with the project, Southern Company's results of operations, cash flow, and financial condition would be materially impacted. The ultimate outcome of this matter cannot be determined at this time.

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Regulatory Matters

In 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4 with a certified capital cost of $4.418 billion. In addition, in 2009 the Georgia PSC approved inclusion of the Plant Vogtle Units 3 and 4 related CWIP accounts in rate base, and the State of Georgia enacted the Georgia Nuclear Energy Financing Act, which allows Georgia Power to recover financing costs for Plant Vogtle Units 3 and 4. Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff up to the certified capital cost of $4.418 billion. As of June 30, 2018, Georgia Power had recovered approximately $1.7 billion of financing costs. Financing costs related to capital costs above $4.418 billion will be recovered through AFUDC; however, Georgia Power will not record AFUDC related to any capital costs in excess of the total deemed reasonable by the Georgia PSC (currently $7.3 billion) and not requested for rate recovery.

Georgia Power is required to file semi-annual VCM reports with the Georgia PSC by February 28 and August 31 of each year. In 2013, in connection with the eighth VCM report, the Georgia PSC approved a stipulation between Georgia Power and the staff of the Georgia PSC to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate in accordance with the 2009 certification order until the completion of Plant Vogtle Unit 3, or earlier if deemed appropriate by the Georgia PSC and Georgia Power.

In 2016, the Georgia PSC voted to approve a settlement agreement (Vogtle Cost Settlement Agreement) resolving certain prudency matters in connection with the fifteenth VCM report. In December 2017, the Georgia PSC voted to approve (and issued its related order on January 11, 2018) certain recommendations made by Georgia Power in the seventeenth VCM report and modifying the Vogtle Cost Settlement Agreement. The Vogtle Cost Settlement Agreement, as modified by the January 11, 2018 order, resolved the following regulatory matters related to Plant Vogtle Units 3 and 4: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report should be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement was reasonable and prudent and none of the amounts paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) (a) capital costs incurred up to $5.68 billion would be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, (b) Georgia Power would have the burden to show that any capital costs above $5.68 billion were prudent, and (c) a revised capital cost forecast of $7.3 billion (after reflecting the impact of payments received under the Guarantee Settlement Agreement and Customer Refunds) was found reasonable; (iv) construction of Plant Vogtle Units 3 and 4 should be completed, with Southern Nuclear serving as project manager and Bechtel as primary contractor; (v) approved and deemed reasonable Georgia Power's revised schedule placing Plant Vogtle Units 3 and 4 in service in November 2021 and November 2022, respectively; (vi) confirmed that the revised cost forecast does not represent a cost cap and that prudence decisions on cost recovery will be made at a later date, consistent with applicable Georgia law; (vii) reduced the ROE used to calculate the NCCR tariff (a) from 10.95% (the ROE rate setting point authorized by the Georgia PSC in the 2013 ARP) to 10.00% effective January 1, 2016, (b) from 10.00% to 8.30%, effective January 1, 2020, and (c) from 8.30% to 5.30%, effective January 1, 2021 (provided that the ROE in no case will be less than Georgia Power's average cost of long-term debt); (viii) reduced the ROE used for AFUDC equity for Plant Vogtle Units 3 and 4 from 10.00% to Georgia Power's average cost of long-term debt, effective January 1, 2018; and (ix) agreed that upon Unit 3 reaching commercial operation, retail base rates would be adjusted to include carrying costs on those capital costs deemed prudent in the Vogtle Cost Settlement Agreement. The January 11, 2018 order also stated that if Plant Vogtle Units 3 and 4 are not commercially operational by June 1, 2021 and June 1, 2022, respectively, the ROE used to calculate the NCCR tariff will be further reduced by 10 basis points each month (but not lower than Georgia Power's average cost of long-term debt) until the respective unit is commercially operational. The ROE reductions negatively impacted earnings by approximately $25 million in 2017 and are estimated to have negative earnings impacts of approximately $100 million in 2018 and an aggregate of $585 million from 2019 to 2022.

In its January 11, 2018 order, the Georgia PSC also stated if other conditions change and assumptions upon which Georgia Power's seventeenth VCM report are based do not materialize, the Georgia PSC reserved the right to reconsider the decision to continue construction.

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

On February 12, 2018, Georgia Interfaith Power & Light, Inc. and Partnership for Southern Equity, Inc. filed a petition appealing the Georgia PSC's January 11, 2018 order with the Fulton County Superior Court. On March 8, 2018, Georgia Watch filed a similar appeal to the Fulton County Superior Court for judicial review of the Georgia PSC's final decision and denial of Georgia Watch's motion for reconsideration. Georgia Power believes the two appeals have no merit; however, an adverse outcome in either appeal could have a material impact on Southern Company's results of operations, financial condition, and liquidity.

The Georgia PSC has approved seventeen VCM reports covering the periods through June 30, 2017, including total construction capital costs incurred through that date of $4.4 billion. On August 21, 2018, the Georgia PSC is scheduled to vote on Georgia Power's eighteenth VCM report, which requested approval of $448 million of construction capital costs (excluding the $1.7 billion received from Toshiba under the Guarantee Settlement Agreement and the $188 million in Customer Refunds recognized as a regulatory liability) incurred from July 1, 2017 through December 31, 2017.

On August 31, 2018, Georgia Power will file its nineteenth VCM report with the Georgia PSC, which will reflect the revised capital cost forecast discussed previously and request approval of $578 million of construction capital costs incurred from January 1, 2018 through June 30, 2018.

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

See RISK FACTORS of Southern Company in Item 1A herein and 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.

DOE Financing

As of June 30, 2018, Georgia Power had borrowed $2.6 billion related to Plant Vogtle Units 3 and 4 costs through the Loan Guarantee Agreement and a multi-advance credit facility among Georgia Power, the DOE, and the FFB, which provides for borrowings of up to $3.46 billion, subject to the satisfaction of certain conditions. In September 2017, the DOE issued a conditional commitment to Georgia Power for up to approximately $1.67 billion in additional guaranteed loans under the Loan Guarantee Agreement. In June 2018, the DOE approved a request by Georgia Power to extend the conditional commitment to September 30, 2018. Any further extension must be approved by the DOE. Final approval and issuance of these additional loan guarantees by the DOE cannot be assured and are subject to the negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions, including the Vogtle Owners' votes to continue construction. See Note 6 to the financial statements of Southern Company under "DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements under "DOE Loan Guarantee Borrowings" herein for additional information, including applicable covenants, events of default, mandatory prepayment events (including any decision not to continue construction of Plant Vogtle Units 3 and 4), and conditions to borrowing.

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

Income Tax Matters

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters" of Southern Company in Item 7 of the Form 10-K and FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk," Note (B) to the Condensed Financial Statements under "Regulatory Matters," and Note (H) to the Condensed Financial Statements herein for information regarding the Tax Reform Legislation and related regulatory actions.

Southern Power

In March 2018, Southern Power substantially completed a legal entity reorganization of various direct and indirect subsidiaries that own and operate substantially all of its solar facilities, including certain subsidiaries owned in partnership with various third parties. The reorganization resulted in net state tax benefits related to certain changes

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

in apportionment rates totaling approximately $50 million, which were recorded in the first quarter 2018. In April 2018, Southern Power completed the final stage of the reorganization resulting in additional net state tax benefits of approximately $4 million.

Southern Power is pursuing the sale of a noncontrolling interest in a portfolio of eight operating wind facilities through the use of third-party tax equity, which, if successful, is expected to close in the fourth quarter 2018. In the third quarter 2018, various direct and indirect subsidiaries of Southern Power that own and operate these wind facilities are expected to be reorganized under a new holding company in which the tax equity partner would invest. The reorganization is expected to result in estimated net state tax benefits totaling approximately $10 million related to certain changes in apportionment rates. The ultimate outcome of this matter cannot be determined at this time.

Other Matters

Southern Company and its subsidiaries are involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Southern Company and its subsidiaries are subject to certain claims and legal actions arising in the ordinary course of business. The business activities of Southern Company's subsidiaries are subject to extensive governmental regulation related to public health and the environment, such as laws and regulations governing air, water, land, and protection of natural resources. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental laws and regulations 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 or regulatory matters cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements herein, 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.

Litigation

In 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 to include, among other things, Southern Company as a defendant. The individual plaintiff alleged that Mississippi Power and Southern Company violated the Mississippi Unfair Trade Practices Act. All plaintiffs 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 County energy facility and that these alleged breaches unjustly enriched Mississippi Power and Southern Company. The plaintiffs sought unspecified actual damages and punitive damages; asked the Circuit Court to appoint a receiver to oversee, operate, manage, and otherwise control all affairs relating to the Kemper County energy facility; asked the Circuit Court to revoke any licenses or certificates authorizing Mississippi Power or Southern Company to engage in any business related to the Kemper County energy facility in Mississippi; and sought attorney's fees, costs, and interest. The plaintiffs also sought an injunction to prevent any Kemper County energy facility costs from being charged to customers through electric rates. In June 2017, the Circuit Court ruled in favor of motions by Southern Company and Mississippi Power and dismissed the case. In July 2017, the plaintiffs filed notice of an appeal. On July 13, 2018, Mississippi Power and Southern Company reached a settlement agreement with the plaintiffs and the plaintiffs' appeal was dismissed with prejudice. The settlement had no material impact on Southern Company's financial statements.

In January 2017, a putative securities class action complaint was filed against Southern Company, certain of its officers, and certain former Mississippi Power officers in the U.S. District Court for the Northern District of Georgia, Atlanta Division, by Monroe County Employees' Retirement System on behalf of all persons who purchased shares of Southern Company's common stock between April 25, 2012 and October 29, 2013. The complaint alleges that Southern Company, certain of its officers, and certain former Mississippi Power officers

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made materially false and misleading statements regarding the Kemper County energy facility in violation of certain provisions under the Securities Exchange Act of 1934, as amended. The complaint seeks, among other things, compensatory damages and litigation costs and attorneys' fees. In June 2017, the plaintiffs filed an amended complaint that provided additional detail about their claims, increased the purported class period by one day, and added certain other former Mississippi Power officers as defendants. In July 2017, the defendants filed a motion to dismiss the plaintiffs' amended complaint with prejudice, to which the plaintiffs filed an opposition in September 2017. On March 29, 2018, the U.S. District Court for the Northern District of Georgia, Atlanta Division, issued an order granting, in part, the defendants' motion to dismiss. The court dismissed certain claims against certain officers of Southern Company and Mississippi Power and dismissed the allegations related to a number of the statements that plaintiffs challenged as being false or misleading. On April 26, 2018, the defendants filed a motion for reconsideration of the court's order, seeking dismissal of the remaining claims in the lawsuit.

In February 2017, Jean Vineyard filed a shareholder derivative lawsuit and, in May 2017, Judy Mesirov filed a shareholder derivative lawsuit, each in the U.S. District Court for the Northern District of Georgia. Each of these lawsuits names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. In August 2017, these two shareholder derivative lawsuits were consolidated in the U.S. District Court for the Northern District of Georgia. The complaints allege that the defendants caused Southern Company to make false or misleading statements regarding the Kemper County energy facility cost and schedule. Further, the complaints allege that the defendants were unjustly enriched and caused the waste of corporate assets and also allege that the individual defendants violated their fiduciary duties. Each plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and, on each plaintiff's own behalf, attorneys' fees and costs in bringing the lawsuit. Each plaintiff also seeks certain changes to Southern Company's corporate governance and internal processes. On April 25, 2018, the court entered an order staying this lawsuit until 30 days after the resolution of any dispositive motions or any settlement, whichever is earlier, in the putative securities class action.

In May 2017, Helen E. Piper Survivor's Trust filed a shareholder derivative lawsuit in the Superior Court of Gwinnett County, State of Georgia that names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. The complaint alleges that the individual defendants, among other things, breached their fiduciary duties in connection with schedule delays and cost overruns associated with the construction of the Kemper County energy facility. The complaint further alleges that the individual defendants authorized or failed to correct false and misleading statements regarding the Kemper County energy facility schedule and cost and failed to implement necessary internal controls to prevent harm to Southern Company. The plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and disgorgement of profits and, on its behalf, attorneys' fees and costs in bringing the lawsuit. The plaintiff also seeks certain unspecified changes to Southern Company's corporate governance and internal processes. The court entered an order staying this lawsuit until 30 days after the resolution of any dispositive motions or any settlement, whichever is earlier, in the putative securities class action.

On May 18, 2018, Southern Company and Mississippi Power received a notice of dispute and arbitration demand filed by Martin Product Sales, LLC (Martin) based on two agreements, both related to Kemper IGCC byproducts for which Mississippi Power provided termination notices in September 2017. Martin alleges breach of contract, breach of good faith and fair dealing, fraud and misrepresentation, and civil conspiracy and makes a claim for damages in the amount of approximately $143 million, as well as additional unspecified damages, attorney's fees, costs, and interest.

Southern Company believes these legal challenges have no merit; however, an adverse outcome in any of 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, the ultimate outcome of which cannot be determined at this time.

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Investments in Leveraged Leases

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Other Matters – Investments in Leveraged Leases" of Southern Company in Item 7 and Note 1 to the financial statements of Southern Company under "Leveraged Leases" in Item 8 of the Form 10-K for additional information regarding a Southern Company Holdings Inc. (Southern Holdings) subsidiary's leveraged lease agreements and concerns about the financial and operational performance of one of the lessees and the associated generation assets.

The ability of the lessees to make required payments to the Southern Holdings subsidiary is dependent on the operational performance of the assets. As a result of operational improvements in the first half of 2018, the June 2018 lease payment was paid in full and the December 2018 lease payment is currently expected to be paid in full. However, operational issues and the resulting cash liquidity challenges persist and significant concerns continue regarding the lessee's ability to make the remaining semi-annual lease payments. These operational challenges may also impact the expected residual value of the assets at the end of the lease term in 2047. If any future lease payment is not paid in full, the Southern Holdings subsidiary may be unable to make its corresponding payment to the holders of the underlying non-recourse debt related to the generation assets. Failure to make the required payment to the debtholders would represent an event of default that would give the debtholders the right to foreclose on, and take ownership of, the generation assets from the Southern Holdings subsidiary, in effect terminating the lease and resulting in the write-off of the related lease receivable, which would result in a reduction in net income of approximately $86 million after tax based on the lease receivable balance as of June 30, 2018. Southern Company has evaluated the recoverability of the lease receivable and the expected residual value of the generation assets at the end of the lease under various scenarios and has concluded that its investment in the leveraged lease is not impaired as of June 30, 2018. Southern Company will continue to monitor the operational performance of the underlying assets and evaluate the ability of the lessee to continue to make the required lease payments. The ultimate outcome of this matter cannot be determined at this time.

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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

Estimated Cost, Schedule, and Rate Recovery for the Construction of Plant Vogtle Units 3 and 4

In December 2016, the Georgia PSC approved the Vogtle Cost Settlement Agreement, which resolved certain prudency matters in connection with Georgia Power's fifteenth VCM report. In December 2017, the Georgia PSC approved Georgia Power's seventeenth VCM report, which included a recommendation to continue construction of Plant Vogtle Units 3 and 4, with Southern Nuclear serving as project manager and Bechtel serving as the primary construction contractor, as well as a modification of the Vogtle Cost Settlement Agreement. The Georgia PSC's related order stated that under the modified Vogtle Cost Settlement Agreement, (i) none of the $3.3 billion of costs incurred through December 31, 2015 should be disallowed as imprudent; (ii) capital costs incurred up to $5.68 billion would be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs; (iii) Georgia Power would have the burden of proof to show that any capital costs above $5.68 billion were prudent; (iv) Georgia Power's total project capital cost forecast of $7.3 billion (net of $1.7 billion received under the Guarantee Settlement Agreement and $188 million in Customer Refunds recognized as a regulatory liability in 2017) was found reasonable and did not represent a cost cap; and (v) prudence decisions would be made subsequent to achieving fuel load for Unit 4.

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In its order, the Georgia PSC also stated if other conditions change and assumptions upon which Georgia Power's seventeenth VCM report are based do not materialize, the Georgia PSC reserved the right to reconsider the decision to continue construction.

In the second quarter 2018, Georgia Power revised its base cost forecast and estimated contingency to complete construction and start-up of Plant Vogtle Units 3 and 4 to $8.0 billion and $0.4 billion, respectively, for a total project capital cost forecast of $8.4 billion (net of $1.7 billion received under the Guarantee Settlement Agreement and $188 million in Customer Refunds recognized as a regulatory liability in 2017). Although Georgia Power believes these incremental costs are reasonable and necessary to complete the project and the Georgia PSC has stated the $7.3 billion estimate included in the seventeenth VCM proceeding does not represent a cost cap, Georgia Power does not intend to seek rate recovery for the $0.7 billion increase in costs included in the revised base capital cost forecast, which will be filed with the Georgia PSC in the nineteenth VCM report on August 31, 2018. In connection with future VCM filings, Georgia Power may request the Georgia PSC to evaluate costs included in the revised construction contingency estimate for rate recovery as and when they are appropriately included in the base capital cost forecast. After considering the significant level of uncertainty that exists regarding the future recoverability of costs included in the construction contingency estimate since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in these future regulatory proceedings, Georgia Power has recorded a total pre-tax charge to income of $1.1 billion ($0.8 billion after tax) as of June 30, 2018.

Georgia Power's revised cost estimate reflects an expected in-service date of November 2021 for Unit 3 and November 2022 for Unit 4.

As construction continues, challenges with management of contractors, subcontractors, and vendors; labor productivity, availability, and/or cost escalation; procurement, fabrication, delivery, assembly, and/or installation, including any required engineering changes, of plant systems, structures, and components (some of which are based on new technology that is just beginning initial operation in the global nuclear industry at this scale); or other issues could arise and change the projected schedule and estimated cost.

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. 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, 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.

The ultimate outcome of these matters cannot be determined at this time. Any extension of the in-service dates of November 2021 for Unit 3 and November 2022 for Unit 4 is currently estimated to result in additional base capital costs of approximately $50 million per month, based on Georgia Power's ownership interests, and AFUDC of approximately $12 million per month. While Georgia Power is not precluded from seeking recovery of any future capital cost forecast increase, management will ultimately determine whether or not to seek recovery. Any further changes to the capital cost forecast that are not expected to be recoverable through regulated rates will be required to be charged to income and such charges could be material.

Given the significant complexity involved in estimating the future costs to complete construction and start-up of Plant Vogtle Units 3 and 4 and the significant management judgment necessary to assess the related uncertainties surrounding future rate recovery of any projected cost increases, as well as the potential impact on Southern Company's results of operations and cash flows, Southern Company considers these items to be critical accounting estimates. See Note 3 to the financial statements of Southern Company under "Nuclear Construction" in Item 8 of

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the Form 10-K and Note (B) to the Condensed Financial Statements under "Nuclear Construction" herein for additional information.

Recently Issued Accounting Standards

See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Recently Issued Accounting Standards" of Southern Company in Item 7 of the Form 10-K for additional information regarding ASU No. 2016-02, Leases (Topic 842). See Note (A) to the Condensed Financial Statements herein for information regarding Southern Company's recently adopted accounting standards.

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, 2018. 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 $3.3 billion for the first six months of 2018, an increase of $0.5 billion from the corresponding period in 2017. The increase in net cash provided from operating activities was primarily due to an increase in fuel cost recovery and an increase in other current liabilities, primarily due to the timing of customer billing reductions related to the Tax Reform Legislation. Net cash used for investing activities totaled $3.6 billion for the first six months of 2018 primarily due to the traditional electric operating companies' installation of equipment to comply with environmental standards and construction of electric generation, transmission, and distribution facilities and capital expenditures for Southern Company Gas' infrastructure replacement programs. Net cash provided from financing activities totaled $0.2 billion for the first six months of 2018 primarily due to an increase in commercial paper borrowings and proceeds from Southern Power's sale of a 33% equity interest in a limited partnership indirectly owning substantially all of its solar facilities, partially offset by common stock dividend payments and net redemptions and repurchases of long-term and short-term debt. 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 2018 include the reclassification of $7.3 billion and $3.5 billion in total assets and liabilities held for sale, respectively, associated with Gulf Power, Elizabethtown Gas, Elkton Gas, and Florida City Gas as described in Note (J) to the Condensed Financial Statements herein under "Assets Held for Sale;" an increase of $2.8 billion in total property, plant, and equipment primarily related to the traditional electric operating companies' installation of equipment to comply with environmental standards and construction of electric generation, transmission, and distribution facilities, as well as an increase in AROs at Alabama Power, partially offset by the charge related to the construction of Plant Vogtle Units 3 and 4; an increase of $2.5 billion in notes payable primarily related to increased commercial paper borrowings and issuances of short-term bank debt; a decrease of $2.3 billion in long-term debt (including amounts due within one year) resulting from the repayment of long-term debt; an increase of $1.7 billion in noncontrolling interests primarily related to Southern Power's sale of a 33% equity interest in a limited partnership indirectly owning substantially all of its solar facilities; and an increase of $1.5 billion in ARO liabilities primarily related to revised estimates for ash pond closure costs at Alabama Power to comply with the CCR Rule. See Notes (A), (B), (F), and (J) to the Condensed Financial Statements under "Asset Retirement Obligations," "Nuclear Construction," "Financing Activities," and "Southern Power – Sale of Solar Facility Interests," respectively, herein for additional information.

At the end of the second quarter 2018, the market price of Southern Company's common stock was $46.31 per share (based on the closing price as reported on the New York Stock Exchange) and the book value was $23.31 per share, representing a market-to-book ratio of 199%, compared to $48.09, $23.99, and 201%, respectively, at the end of

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2017. Southern Company's common stock dividend for the second quarter 2018 was $0.60 per share compared to $0.58 per share in the second quarter 2017.

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 and contractual obligations. Approximately $2.2 billion will be required through June 30, 2019 to fund maturities of long-term debt. See "Sources of Capital" herein for additional information.

The Southern Company system's construction program is currently estimated to total approximately $8.8 billion for 2018, $8.2 billion for 2019, $7.2 billion for 2020, $7.0 billion for 2021, and $6.7 billion for 2022. These amounts include expenditures of approximately $1.4 billion, $1.4 billion, $0.9 billion, $1.0 billion, and $0.6 billion for the construction of Plant Vogtle Units 3 and 4 in 2018, 2019, 2020, 2021, and 2022, respectively, and an average of approximately $0.5 billion per year for 2018 through 2022 for Southern Power's planned expenditures for plant acquisitions and placeholder growth, as revised subsequent to Tax Reform Legislation. These amounts also include capital expenditures related to contractual purchase commitments for nuclear fuel, capital expenditures covered under LTSAs, and costs, which are immaterial to Southern Company, relating to assets divested during 2018 and held for sale at June 30, 2018. Estimated capital expenditures to comply with environmental laws and regulations included in these amounts are $1.1 billion, $0.3 billion, $0.4 billion, $0.5 billion, and $0.5 billion for 2018, 2019, 2020, 2021, and 2022, respectively. These estimated expenditures do not include any potential compliance costs associated with the regulation of CO₂ emissions from fossil fuel-fired electric generating units.

The traditional electric operating companies also anticipate costs associated with closure and monitoring of ash ponds in accordance with the CCR Rule, which are reflected in Southern Company's ARO liabilities. These costs, which are expected to change as the Southern Company system continues to refine its assumptions underlying the cost estimates and evaluate the method and timing of compliance activities, are currently estimated to be approximately $0.3 billion, $0.4 billion, $0.5 billion, $0.6 billion, and $0.5 billion for 2018, 2019, 2020, 2021, and 2022, respectively. For information regarding expected changes to these cost estimates during the second half of 2018, see FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Coal Combustion Residuals" and Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein. Also see Note 1 to the financial statements of Southern Company under "Asset Retirement Obligations and Other Costs of Removal" in Item 8 of the Form 10-K for additional information on AROs.

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 laws and regulations; the outcome of any legal challenges to environmental rules; changes in electric generating plants, including unit retirements and replacements and adding or changing fuel sources at existing electric generating units, to meet regulatory requirements; changes in FERC rules and regulations; state regulatory agency 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 (J) to the Condensed Financial Statements under "Southern Power" herein for additional information regarding Southern Power's plant acquisitions.

The construction program also includes Plant Vogtle Units 3 and 4, which includes components based on new technology that is just beginning initial operation in the global nuclear industry at scale and which may be subject to additional revised cost estimates during construction. The ability to control costs and avoid cost and schedule overruns during the development, construction, and operation of new facilities is subject to a number of factors, including, but not limited to, changes in labor costs, availability, and productivity, challenges with management of

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contractors, subcontractors, or vendors, 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. See Note 3 to the financial statements of Southern Company under "Nuclear Construction" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Nuclear Construction" herein for information regarding Plant Vogtle Units 3 and 4 and additional factors that may impact construction expenditures.

Sources of Capital

Southern Company intends to meet its future capital needs through operating cash flows, borrowings from financial institutions, and debt and equity issuances in the capital markets. Southern Company also plans to utilize the proceeds from the disposition of Gulf Power when completed for future capital needs. 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 and debt issuances in 2018, as well as in subsequent years, will be contingent on Southern Company's investment opportunities and the Southern Company system's capital requirements and will depend upon prevailing market conditions and other factors. See "Capital Requirements and Contractual Obligations" herein for additional information.

Except as described herein, the traditional electric operating companies, Southern Power, and Southern Company Gas plan to obtain the funds required for construction and other purposes from operating cash flows, external security issuances, borrowings from financial institutions, and equity contributions or loans from Southern Company. Southern Power also plans to utilize tax equity partnership contributions. Southern Company Gas also plans to utilize the proceeds from the dispositions of Elizabethtown Gas, Elkton Gas, Florida City Gas, and Pivotal Home Solutions for future capital needs. 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, in 2014, Georgia Power entered into the Loan Guarantee Agreement with the DOE, under which the proceeds of borrowings 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. As of June 30, 2018, Georgia Power had borrowed $2.6 billion under the FFB Credit Facility. In July 2017, Georgia Power entered into an amendment to the Loan Guarantee Agreement, which provides that further advances are conditioned upon the DOE's approval of any agreements entered into in replacement of the Vogtle 3 and 4 Agreement and satisfaction of certain other conditions.

In September 2017, the DOE issued a conditional commitment to Georgia Power for up to approximately $1.67 billion of additional guaranteed loans under the Loan Guarantee Agreement. This conditional commitment expires on September 30, 2018, subject to any further extension approved by the DOE. Final approval and issuance of these additional loan guarantees by the DOE cannot be assured and are subject to the negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions, including the Vogtle Owners' votes to continue construction. See Note 6 to the financial statements of Southern Company under "DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements under "DOE Loan Guarantee Borrowings" herein for additional information regarding the Loan Guarantee Agreement, including applicable covenants, events of default, mandatory prepayment events (including any decision not to continue construction of Plant Vogtle Units 3 and 4), and additional conditions to borrowing. Also see Note (B) to the Condensed Financial Statements under "Nuclear Construction" herein for additional information regarding Plant Vogtle Units 3 and 4.

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As of June 30, 2018, Southern Company's current liabilities exceeded current assets by $2.7 billion due to notes payable of $5.0 billion (comprised of approximately $3.0 billion at the parent company, $0.5 billion at Georgia Power, $0.1 billion at Gulf Power, $0.1 billion at Mississippi Power, $0.3 billion at Southern Power, and $1.0 billion at Southern Company Gas) and long-term debt that is due within one year of $2.2 billion (comprised of approximately $1.0 billion at the parent company, $0.2 billion at Alabama Power, $0.5 billion at Georgia Power, $0.3 billion at Mississippi Power, and $0.2 billion at Southern Company Gas). To meet short-term cash needs and contingencies, the Southern Company system 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, Southern Power, and Southern Company Gas, equity contributions and/or loans from Southern Company to meet their short-term capital needs.

At June 30, 2018, Southern Company and its subsidiaries had approximately $2.0 billion of cash and cash equivalents. Committed credit arrangements with banks at June 30, 2018 were as follows:

	Expires												Executable Term Loans		Expires Within One Year
Company	2018		2019		2020		2022		Total		Unused		One Year		Term Out		No Term Out
	(in millions)
Southern Company(a)	$	—	$	—	$	—	$	2,000	$	2,000	$	1,999	$	—	$	—	$	—
Alabama Power	2		31		500		800		1,333		1,333		—		—		33
Georgia Power	—		—		—		1,750		1,750		1,736		—		—		—
Gulf Power	20		25		235		—		280		280		45		45		—
Mississippi Power	100		—		—		—		100		100		—		—		100
Southern Power Company(b)	—		—		—		750		750		728		—		—		—
Southern Company Gas(c)	—		—		—		1,900		1,900		1,895		—		—		—
Other	—		30		—		—		30		30		—		—		30
Southern Company Consolidated	$	122	$	86	$	735	$	7,200	$	8,143	$	8,101	$	45	$	45	$	163

(a) Represents the Southern Company parent entity.

(b) Does not include Southern Power's $120 million continuing letter of credit facility for standby letters of credit expiring in 2019, of which $23 million remains unused at June 30, 2018.

(c) Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $1.4 billion of these arrangements. Southern Company Gas' committed credit arrangements also include $500 million for which Nicor Gas is the borrower and which is restricted for working capital needs of Nicor Gas.

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

Most of these bank credit arrangements, as well as the term loan arrangements of Southern Company, Alabama Power, Mississippi Power, and Southern Power Company contain covenants that limit debt levels and contain cross-acceleration or cross-default provisions to other indebtedness (including guarantee obligations) that are restricted only to the indebtedness of the individual company. Such cross-default provisions to other indebtedness would trigger an event of default if the applicable borrower defaulted on indebtedness or guarantee obligations over a specified threshold. Such cross-acceleration provisions to other indebtedness would trigger an event of default if the applicable borrower defaulted on indebtedness, the payment of which was then accelerated. At June 30, 2018, Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company

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Gas, and Nicor Gas were in compliance with all such covenants. All but $40 million of the bank credit arrangements do not 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 revenue bonds of the traditional electric operating companies and the commercial paper programs of Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company Gas, and Nicor Gas. The amount of variable rate revenue bonds of the traditional electric operating companies outstanding requiring liquidity support as of June 30, 2018 was approximately $1.5 billion. In addition, at June 30, 2018, the traditional electric operating companies had approximately $482 million of revenue bonds outstanding that were required to be remarketed within the next 12 months. Subsequent to June 30, 2018, approximately $43 million of these pollution control revenue bonds of Mississippi Power were purchased and held by Mississippi Power.

Southern Company, the traditional electric operating companies (other than Mississippi Power), Southern Power Company, Southern Company Gas, and Nicor Gas make short-term borrowings primarily through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above. 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, 2018				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	$	3,002	2.5	%	$	2,292	2.4	%	$	3,042
Short-term bank debt	1,979		3.0	%	1,987		2.8	%	2,254
Total	$	4,981	2.7	%	$	4,279	2.6	%

(*) Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 2018.

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, 2018, 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 and natural gas 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.

48

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, 2018 were as follows:

Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB and/or Baa2	$	38
At BBB- and/or Baa3	$	576
At BB+ and/or Ba1(*)	$	2,141

(*) Any additional credit rating downgrades at or below BB- and/or Ba3 could increase collateral requirements up to an additional $38 million.

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 February 26, 2018, Moody's revised its rating outlook for Mississippi Power from stable to positive.

On February 28, 2018, Fitch downgraded the senior unsecured long-term debt rating of Southern Company to BBB+ from A- with a stable outlook and of Georgia Power to A from A+ with a negative outlook.

On March 14, 2018, S&P upgraded the senior unsecured long-term debt rating of Mississippi Power to A- from BBB+. The outlook remained negative.

On May 21, 2018, S&P revised its rating outlook for Gulf Power from negative to stable.

As a result of the Tax Reform Legislation, certain financial metrics, such as the funds from operations to debt percentage, used by the credit rating agencies to assess Southern Company and its subsidiaries may be negatively impacted. Southern Company and certain of its subsidiaries are taking actions to mitigate the resulting impacts, which, among other alternatives, include adjusting capital structure. Absent actions by Southern Company and its subsidiaries that fully mitigate the impacts, the credit ratings of Southern Company and certain of its subsidiaries could be negatively affected. See Note 3 to the financial statements of Southern Company in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for additional information related to state PSC or other regulatory agency actions related to the Tax Reform Legislation, including recent approvals of capital structure adjustments for Alabama Power, Georgia Power, Gulf Power, and Atlanta Gas Light by their respective state PSCs, which are expected to help mitigate the potential adverse impacts to certain of their credit metrics.

Financing Activities

During the first six months of 2018, Southern Company issued approximately 6.6 million shares of common stock primarily through employee equity compensation plans and received proceeds of approximately $222 million.

49

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first six months of 2018:

Company	Senior Note Issuances		Senior Note Maturities, Redemptions, and Repurchases		Revenue Bond Maturities, Redemptions, and Repurchases		Other Long-Term Debt Redemptions and Maturities(*)
	(in millions)
Alabama Power	$	500	$	—	$	—	$	—
Georgia Power	—		1,000		398		104
Mississippi Power	600		—		—		900
Southern Power	—		350		—		420
Southern Company Gas	—		—		200		—
Other	—		—		—		7
Southern Company Consolidated	$	1,100	$	1,350	$	598	$	1,431

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

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

In March 2018, Southern Company entered into a $900 million short-term floating rate bank loan bearing interest based on one-month LIBOR.

In April 2018, Southern Company borrowed $250 million pursuant to a short-term uncommitted bank credit arrangement, which bears interest at a rate agreed upon by Southern Company and the bank from time to time and is payable on no less than 30 days' demand by the bank.

In June 2018, Southern Company repaid at maturity two $100 million short-term floating rate bank term loans.

In January 2018, Georgia Power repaid its outstanding $150 million short-term floating rate bank loan due May 31, 2018.

In May 2018, through cash tender offers, Georgia Power repurchased and retired $89 million of the $250 million aggregate principal amount outstanding of its Series 2007A 5.65% Senior Notes due March 1, 2037, $326 million of the $500 million aggregate principal amount outstanding of its Series 2009A 5.95% Senior Notes due February 1, 2039, and $335 million of the $600 million aggregate principal amount outstanding of its Series 2010B 5.40% Senior Notes due June 1, 2040, for an aggregate purchase price, excluding accrued and unpaid interest, of $902 million.

In March 2018, Mississippi Power entered into a $300 million short-term floating rate bank loan bearing interest based on one-month LIBOR, of which $200 million was repaid in the second quarter 2018 and $50 million was repaid on July 31, 2018. The proceeds of this loan, together with the proceeds of Mississippi Power's $600 million senior notes issuances, were used to repay Mississippi Power's $900 million unsecured floating rate term loan.

Subsequent to June 30, 2018, approximately $43 million in pollution control revenue bonds of Mississippi Power were purchased and held by Mississippi Power. These bonds may be remarketed to the public in the future.

In May 2018, Southern Power entered into two short-term floating rate bank loans, each for an aggregate principal amount of $100 million, which bear interest based on one-month LIBOR.

In the second quarter 2018, Pivotal Utility Holdings caused $200 million aggregate principal amount of gas facility revenue bonds to be redeemed. Also in the second quarter 2018, Pivotal Utility Holdings, as borrower, and Southern Company Gas, as guarantor, entered into a $181 million short-term delayed draw floating rate bank term loan

50

SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

bearing interest based on one-month LIBOR, which Pivotal Utility Holdings used to repay the gas facility revenue bonds. Subsequent to June 30, 2018, Pivotal Utility Holdings repaid this short-term loan.

In May 2018, Southern Company Gas Capital borrowed $95 million pursuant to a short-term uncommitted bank credit arrangement, guaranteed by Southern Company Gas, bearing interest at a rate agreed upon by Southern Company Gas Capital and the bank from time to time and payable on no less than 30 days' demand by the bank. The proceeds of the loan were used to pay down short-term debt. Subsequent to June 30, 2018, Southern Company Gas Capital repaid this loan.

Subsequent to June 30, 2018, Nicor Gas agreed to issue $300 million aggregate principal amount of first mortgage bonds in a private placement, $100 million of which is expected to be issued in August 2018 and $200 million of which is expected to be issued in November 2018.

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.

51

PART I

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

During the three months ended June 30, 2018, there were no material changes to Southern Company's, Alabama Power's, Georgia Power's, Gulf Power's, Mississippi Power's, and Southern Power's disclosures about market risk. For additional market risk disclosures relating to Southern Company Gas, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of Southern Company Gas herein. 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, Mississippi Power, and Southern Company Gas, and Note 9 to the financial statements of Southern Power in Item 8 of the Form 10-K. Also see Note (D) and Note (I) 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, Southern Power, and Southern Company Gas 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, Southern Power's, or Southern Company Gas' 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 2018 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, Southern Power's, or Southern Company Gas' internal control over financial reporting.

52

ALABAMA POWER COMPANY

53

ALABAMA POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2018			2017			2018			2017
	(in millions)						(in millions)
Operating Revenues:
Retail revenues	$	1,338		$	1,333		$	2,624		$	2,560
Wholesale revenues, non-affiliates	65			68			139			133
Wholesale revenues, affiliates	31			32			82			65
Other revenues	69			51			131			108
Total operating revenues	1,503			1,484			2,976			2,866
Operating Expenses:
Fuel	347			303			672			601
Purchased power, non-affiliates	48			40			113			75
Purchased power, affiliates	43			34			80			62
Other operations and maintenance	402			389			788			772
Depreciation and amortization	189			183			379			364
Taxes other than income taxes	94			95			192			191
Total operating expenses	1,123			1,044			2,224			2,065
Operating Income	380			440			752			801
Other Income and (Expense):
Allowance for equity funds used during construction	14			8			27			16
Interest expense, net of amounts capitalized	(80		)	(77		)	(158		)	(153		)
Other income (expense), net	12			15			15			25
Total other income and (expense)	(54		)	(54		)	(116		)	(112		)
Earnings Before Income Taxes	326			386			636			689
Income taxes	64			151			145			277
Net Income	262			235			491			412
Dividends on Preferred and Preference Stock	3			5			7			9
Net Income After Dividends on Preferred and Preference Stock	$	259		$	230		$	484		$	403

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2018		2017		2018		2017
	(in millions)				(in millions)
Net Income	$	262	$	235	$	491	$	412
Other comprehensive income (loss):
Qualifying hedges:
Reclassification adjustment for amounts included in net income, net of tax of $-, $1, $1, and $1, respectively	1		1		2		2
Total other comprehensive income (loss)	1		1		2		2
Comprehensive Income	$	263	$	236	$	493	$	414

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

54

ALABAMA POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Six Months Ended June 30,
	2018			2017
	(in millions)
Operating Activities:
Net income	$	491		$	412
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	452			442
Deferred income taxes	48			192
Allowance for equity funds used during construction	(27		)	(16		)
Pension, postretirement, and other employee benefits	(28		)	(24		)
Other, net	(40		)	20
Changes in certain current assets and liabilities —
-Receivables	(153		)	(58		)
-Prepayments	(57		)	(56		)
-Materials and supplies	(47		)	(18		)
-Other current assets	29			12
-Accounts payable	(196		)	(154		)
-Accrued taxes	134			52
-Accrued compensation	(70		)	(74		)
-Retail fuel cost over recovery	—			(65		)
-Other current liabilities	116			7
Net cash provided from operating activities	652			672
Investing Activities:
Property additions	(997		)	(738		)
Nuclear decommissioning trust fund purchases	(131		)	(117		)
Nuclear decommissioning trust fund sales	131			117
Cost of removal, net of salvage	(34		)	(54		)
Change in construction payables	(29		)	48
Other investing activities	(15		)	(15		)
Net cash used for investing activities	(1,075		)	(759		)
Financing Activities:
Proceeds —
Senior notes	500			550
Capital contributions from parent company	488			327
Redemptions — Senior notes	—			(200		)
Payment of common stock dividends	(402		)	(357		)
Other financing activities	(21		)	(14		)
Net cash provided from financing activities	565			306
Net Change in Cash, Cash Equivalents, and Restricted Cash	142			219
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	544			420
Cash, Cash Equivalents, and Restricted Cash at End of Period	$	686		$	639
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $10 and $6 capitalized for 2018 and 2017, respectively)	$	143		$	140
Income taxes, net	17			88
Noncash transactions — Accrued property additions at end of period	216			132

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

55

ALABAMA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Assets	At June 30, 2018			At December 31, 2017
	(in millions)
Current Assets:
Cash and cash equivalents	$	686		$	544
Receivables —
Customer accounts receivable	401			355
Unbilled revenues	174			162
Under recovered regulatory clause revenues	28			—
Affiliated	54			43
Other accounts and notes receivable	41			55
Accumulated provision for uncollectible accounts	(10		)	(9		)
Fossil fuel stock	154			184
Materials and supplies	518			458
Prepaid expenses	90			85
Other regulatory assets, current	146			124
Other current assets	11			5
Total current assets	2,293			2,006
Property, Plant, and Equipment:
In service	29,374			27,326
Less: Accumulated provision for depreciation	9,813			9,563
Plant in service, net of depreciation	19,561			17,763
Nuclear fuel, at amortized cost	337			339
Construction work in progress	1,172			908
Total property, plant, and equipment	21,070			19,010
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	66			67
Nuclear decommissioning trusts, at fair value	906			903
Miscellaneous property and investments	124			124
Total other property and investments	1,096			1,094
Deferred Charges and Other Assets:
Deferred charges related to income taxes	234			239
Deferred under recovered regulatory clause revenues	121			54
Other regulatory assets, deferred	1,244			1,272
Other deferred charges and assets	212			189
Total deferred charges and other assets	1,811			1,754
Total Assets	$	26,270		$	23,864

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

56

ALABAMA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholder's Equity	At June 30, 2018			At December 31, 2017
	(in millions)
Current Liabilities:
Securities due within one year	$	200		$	—
Accounts payable —
Affiliated	298			327
Other	398			585
Customer deposits	95			92
Accrued taxes	137			54
Accrued interest	81			77
Accrued compensation	140			205
Other regulatory liabilities, current	118			1
Other current liabilities	143			59
Total current liabilities	1,610			1,400
Long-term Debt	7,922			7,628
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	2,829			2,760
Deferred credits related to income taxes	2,061			2,082
Accumulated deferred ITCs	109			112
Employee benefit obligations	275			304
Asset retirement obligations	3,085			1,702
Other cost of removal obligations	580			609
Other regulatory liabilities, deferred	43			84
Other deferred credits and liabilities	64			63
Total deferred credits and other liabilities	9,046			7,716
Total Liabilities	18,578			16,744
Redeemable Preferred Stock	291			291
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	3,480			2,986
Retained earnings	2,729			2,647
Accumulated other comprehensive loss	(30		)	(26		)
Total common stockholder's equity	7,401			6,829
Total Liabilities and Stockholder's Equity	$	26,270		$	23,864

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

57

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

SECOND QUARTER 2018 vs. SECOND QUARTER 2017

AND

YEAR-TO-DATE 2018 vs. YEAR-TO-DATE 2017

OVERVIEW

Alabama Power operates as a vertically integrated utility providing electric service to retail and wholesale customers within its traditional service territory located in 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 providing electric service. These factors include the ability to maintain a constructive regulatory environment, to maintain and grow energy sales and customers, and to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand growth, 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. On May 1, 2018, the Alabama PSC approved modifications to Rate RSE and other commitments designed to position Alabama Power to address the retail rate impact and the growing pressure on its credit quality resulting from the Tax Reform Legislation. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters" and FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" herein for additional information and Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Rate RSE" in Item 8 of the Form 10-K for additional information on Alabama Power's established retail tariff.

Alabama Power continues to focus on several key performance indicators including, but not limited to, customer satisfaction, plant availability, system reliability, and net income after dividends on preferred stock.

RESULTS OF OPERATIONS

Net Income

Second Quarter 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$29	12.6	$81	20.1

Alabama Power's net income after dividends on preferred and preference stock for the second quarter 2018 was $259 million compared to $230 million for the corresponding period in 2017. The increase was primarily related to an increase in retail revenues associated with warmer weather experienced in Alabama Power's service territory in the second quarter 2018 compared to the corresponding period in 2017 and a decrease in income tax expense, partially offset by revenues deferred as a regulatory liability for reductions to customer billings, which began in July 2018, related to the Tax Reform Legislation.

Alabama Power's net income after dividends on preferred and preference stock for year-to-date 2018 was $484 million compared to $403 million for the corresponding period in 2017. The increase was primarily related to an increase in retail revenues associated with colder weather experienced in the first quarter 2018 and warmer weather experienced in the second quarter 2018 in Alabama Power's service territory compared to the corresponding periods in 2017 and a decrease in income tax expense, partially offset by revenues deferred as a regulatory liability for reductions to customer billings, which began in July 2018, related to the Tax Reform Legislation and an increase in depreciation. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters" herein and Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Rate RSE" in Item 8 of the Form 10-K for additional information.

58

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Retail Revenues

Second Quarter 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$5	0.4	$64	2.5

In the second quarter 2018, retail revenues were $1.34 billion compared to $1.33 billion for the corresponding period in 2017. For year-to-date 2018, retail revenues were $2.62 billion compared to $2.56 billion for the corresponding period in 2017.

Details of the changes in retail revenues were as follows:

	Second Quarter 2018					Year-to-Date 2018
	(in millions)			(% change)		(in millions)			(% change)
Retail – prior year	$	1,333				$	2,560
Estimated change resulting from –
Rates and pricing	(57		)	(4.2	)	(108		)	(4.2	)
Sales decline	(7		)	(0.6	)	(5		)	(0.2	)
Weather	28			2.1		92			3.6
Fuel and other cost recovery	41			3.1		85			3.3
Retail – current year	$	1,338		0.4	%	$	2,624		2.5	%

Revenues associated with changes in rates and pricing decreased in the second quarter and year-to-date 2018 when compared to the corresponding periods in 2017 primarily due to revenues deferred as a regulatory liability for reductions to customer billings, which began in July 2018, related to the Tax Reform Legislation. See Note (B) to the Condensed Financial Statements under "Regulatory Matters – Alabama Power" herein and 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 decreased in the second quarter and year-to-date 2018 when compared to the corresponding periods in 2017. Weather-adjusted commercial KWH sales decreased 2.3% and 1.6% for the second quarter and year-to-date 2018, respectively, and weather-adjusted residential KWH sales decreased 0.9% and 0.7% for the second quarter and year-to-date 2018, respectively, when compared to the corresponding periods in 2017 primarily due to lower customer usage related to energy efficiency. Industrial KWH sales increased 1.6% and 3.0% for the second quarter and year-to-date 2018, respectively, when compared to the corresponding periods in 2017 as a result of an increase in demand resulting from changes in production levels primarily in the pipelines and primary metals sectors, partially offset by a decrease in demand in the paper sector.

Revenues resulting from changes in weather increased in the second quarter and year-to-date 2018 due to colder weather experienced in the first quarter 2018 and warmer weather experienced in the second quarter 2018 in Alabama Power's service territory compared to the corresponding periods in 2017. For the second quarter 2018, the resulting increases were 3.9% and 1.7% for residential and commercial sales revenues, respectively. For year-to-date 2018, the resulting increases were 7.0% and 2.4% for residential and commercial sales revenues, respectively.

Fuel and other cost recovery revenues increased in the second quarter and year-to-date 2018 when compared to the corresponding periods in 2017 primarily due to increases in KWH generation and the average cost of fuel.

Electric rates include provisions to recognize the full recovery of fuel costs, purchased power costs, PPAs certificated by the Alabama PSC, and costs associated with the 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.

59

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Wholesale Revenues – Affiliates

Second Quarter 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$(1)	(3.1)	$17	26.2

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

For year-to-date 2018, wholesale revenues from sales to affiliates were $82 million compared to $65 million for the corresponding period in 2017. The increase was primarily due to an 12.4% increase in the price of energy and an 11.3% increase in KWH sales as a result of increased demand due to colder weather in the first quarter 2018 compared to the corresponding period in 2017.

Other Revenues

Second Quarter 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$18	35.3	$23	21.3

In the second quarter 2018, other revenues were $69 million compared to $51 million for the corresponding period in 2017. For year-to-date 2018, other revenues were $131 million compared to $108 million for the corresponding period in 2017. These increases were primarily due to revenues related to unregulated sales of products and services that were reclassified as other revenues as a result of the adoption of ASC 606, Revenue from Contracts with Customers (ASC 606). In prior periods, these revenues were included in other income (expense), net. See Note (A) to the Condensed Financial Statements herein for additional information regarding Alabama Power's adoption of ASC 606. The year-to-date 2018 increase was partially offset by decreases in open access transmission tariff revenues and miscellaneous rents.

Fuel and Purchased Power Expenses

	Second Quarter 2018 vs. Second Quarter 2017			Year-to-Date 2018 vs. Year-to-Date 2017
	(change in millions)		(% change)	(change in millions)		(% change)
Fuel	$	44	14.5	$	71	11.8
Purchased power – non-affiliates	8		20.0	38		50.7
Purchased power – affiliates	9		26.5	18		29.0
Total fuel and purchased power expenses	$	61		$	127

In the second quarter 2018, fuel and purchased power expenses were $438 million compared to $377 million for the corresponding period in 2017. The increase was primarily due to a $39 million increase related to the volume of KWHs generated and purchased and a $7 million increase related to the average cost of fuel, partially offset by a $14 million decrease in the average cost of purchased power.

For year-to-date 2018, fuel and purchased power expenses were $865 million compared to $738 million for the corresponding period in 2017. The increase was primarily due to a $75 million increase related to the volume of KWHs generated and purchased, a $16 million increase related to the average cost of fuel, and a $7 million increase in the average cost of purchased power.

60

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

In addition, fuel expense increased $30 million in both the second quarter and year-to-date 2018 in accordance with an Alabama PSC accounting order authorizing the use of excess deferred income taxes to offset under recovered fuel costs. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Accounting Order" herein for additional information.

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. 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 2018	Second Quarter 2017	Year-to-Date 2018	Year-to-Date 2017
Total generation (in billions of KWHs)	15	15	31	30
Total purchased power (in billions of KWHs)	2	1	3	2
Sources of generation (percent) —
Coal	53	47	52	48
Nuclear	20	25	21	26
Gas	20	20	19	20
Hydro	7	8	8	6
Cost of fuel, generated (in cents per net KWH)(a)—
Coal	2.79	2.63	2.74	2.61
Nuclear	0.80	0.76	0.77	0.75
Gas	2.51	2.75	2.69	2.76
Average cost of fuel, generated (in cents per net KWH)(a)(b)	2.31	2.14	2.27	2.13
Average cost of purchased power (in cents per net KWH)(c)	4.72	5.43	5.72	5.50

(a) Cost of fuel and average cost of fuel, generated excludes a $30 million adjustment associated with the Alabama PSC accounting order related to excess deferred income taxes.

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

(c) 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 2018, fuel expense was $347 million compared to $303 million for the corresponding period in 2017. The increase was primarily due to a 24.9% decrease in the volume of KWHs generated by nuclear facilities, a 12.4% decrease in the volume of KWHs generated by hydro facilities, an 8.7% increase in the volume of KWHs generated by coal, a 6.1% increase in the average cost of coal per KWH generated, and a 5.3% increase in the average cost of nuclear per KWH generated. These increases were partially offset by an 8.7% decrease in the average cost of natural gas per KWH generated, which excludes fuel associated with tolling agreements.

For year-to-date 2018, fuel expense was $672 million compared to $601 million for the corresponding period in 2017. The increase was primarily due to a 14.2% decrease in the volume of KWHs generated by nuclear facilities, a 9.8% increase in the volume of KWHs generated by coal, and a 5.0% increase in the average cost of coal per KWH generated. These increases were partially offset by a 22.6% increase in the volume of KWHs generated by hydro facilities.

In addition, fuel expense increased $30 million in both the second quarter and year-to-date 2018 in accordance with an Alabama PSC accounting order authorizing the use of excess deferred income taxes to offset under recovered

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fuel costs. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Accounting Order" herein for additional information.

Purchased Power – Non-Affiliates

In the second quarter 2018, purchased power expense from non-affiliates was $48 million compared to $40 million for the corresponding period in 2017. The increase was primarily related to a 24.6% increase in the amount of energy purchased due to warmer weather in the second quarter 2018 compared to the corresponding period in 2017. This increase was partially offset by a 4.4% decrease in the average cost of purchased power per KWH due to lower natural gas prices.

For year-to-date 2018, purchased power expense from non-affiliates was $113 million compared to $75 million for the corresponding period in 2017. The increase was primarily related to a 29.6% increase in the amount of energy purchased and a 15.6% increase in the average cost of purchased power per KWH due to colder weather in the first quarter 2018 compared to the corresponding period in 2017.

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 2018, purchased power expense from affiliates was $43 million compared to $34 million for the corresponding period in 2017. The increase was primarily related to a 60.8% increase in the amount of energy purchased due to warmer weather in the second quarter 2018 compared to the corresponding period in 2017, partially offset by a 20.9% decrease in the average cost of purchased power per KWH due to lower natural gas prices in the second quarter 2018 compared to the corresponding period in 2017.

For year-to-date 2018, purchased power expense from affiliates was $80 million compared to $62 million for the corresponding period in 2017. The increase was primarily related to a 44% increase in the amount of energy purchased as a result of colder weather in the first quarter 2018 compared to the corresponding period in 2017, partially offset by a 9.8% decrease in the average cost of purchased power per KWH due to lower natural gas prices in the second quarter 2018 compared to the corresponding period in 2017.

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 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$13	3.3	$16	2.1

In the second quarter 2018, other operations and maintenance expenses were $402 million compared to $389 million for the corresponding period in 2017. The increase was primarily due to $12 million of expenses from unregulated sales of products and services that were reclassified as other operations and maintenance expenses as a result of the adoption of ASC 606. In prior periods, these expenses were included in other income (expense), net. In addition, distribution costs increased $5 million primarily due to line maintenance. These increases were partially offset by a $4 million decrease in nuclear generation costs primarily due to the timing of plant improvement projects.

For year-to-date 2018, other operations and maintenance expenses were $788 million compared to $772 million for the corresponding period in 2017. The increase was primarily due to $21 million of expenses from unregulated sales of products and services that were reclassified as other operations and maintenance expenses as a result of the adoption of ASC 606. In prior periods, these expenses were included in other income (expense), net. In addition,

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distribution costs increased $11 million primarily due to line maintenance. These increases were partially offset by a $6 million decrease in property insurance primarily due to the receipt of refunds, a $5 million decrease in steam generation costs primarily due to the timing of outages, and a $5 million decrease in nuclear generation costs primarily due to the timing of plant improvement projects.

See Note (A) to the Condensed Financial Statements herein for additional information regarding Alabama Power's adoption of ASC 606.

Depreciation and Amortization

Second Quarter 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$6	3.3	$15	4.1

For year-to-date 2018, depreciation and amortization was $379 million compared to $364 million for the corresponding period in 2017. This increase was primarily due to additional plant in service related to steam generation, transmission, and distribution assets. See Note 1 to the financial statements of Alabama Power under "Depreciation and Amortization" in Item 8 of the Form 10-K for additional information.

Allowance for Equity Funds Used During Construction

Second Quarter 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$6	75.0	$11	68.8

In the second quarter 2018, AFUDC equity was $14 million compared to $8 million for the corresponding period in 2017. For year-to-date 2018, AFUDC equity was $27 million compared to $16 million for the corresponding period in 2017. These increases were primarily due to an increase in capital expenditures related to environmental and transmission projects.

Other Income (Expense), Net

Second Quarter 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$(3)	(20.0)	$(10)	(40.0)

In the second quarter 2018, other income (expense), net was $12 million compared to $15 million for the corresponding period in 2017. For year-to-date 2018, other income (expense), net was $15 million compared to $25 million for the corresponding period in 2017. These decreases were primarily due to the reclassification of revenues and expenses associated with unregulated sales of products and services to other revenues and operations and maintenance expense, respectively, as a result of the adoption of ASC 606. See Note (A) to the Condensed Financial Statements herein for additional information regarding Alabama Power's adoption of ASC 606.

Income Taxes

Second Quarter 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$(87)	(57.6)	$(132)	(47.7)

In the second quarter 2018, income taxes were $64 million compared to $151 million for the corresponding period in 2017. For year-to-date 2018, income taxes were $145 million compared to $277 million for the corresponding period in 2017. These decreases were primarily due to the reduction in the federal income tax rate and the benefit from the flowback of excess deferred income taxes as a result of the Tax Reform Legislation and lower pre-tax net

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income. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Accounting Order" and Note (H) to the Condensed Financial Statements under "Effective Tax Rate" herein 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 providing electric service. 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 and limited projected demand growth over the next several years. Future earnings will be impacted by customer growth. Earnings will also depend upon maintaining and growing sales, considering, among other things, the adoption and/or penetration rates of increasingly energy-efficient technologies and increasing volumes of electronic commerce transactions, both of which could contribute to a net reduction in customer usage. Earnings are subject to a variety of other 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 the pace of economic growth that 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

Alabama Power's operations are regulated by state and federal environmental agencies through a variety of laws and regulations governing air, water, land, and protection of other natural resources. Alabama Power maintains comprehensive environmental compliance and greenhouse gas (GHG) strategies to assess upcoming requirements and compliance costs associated with these environmental laws and regulations. The costs, including capital expenditures and operations and maintenance costs, required to comply with environmental laws and regulations and to achieve stated goals may impact future unit retirement and replacement decisions, results of operations, cash flows, and financial condition. Related costs may result from the installation of additional environmental controls, closure and monitoring of CCR facilities, unit retirements, and adding or changing fuel sources for certain existing units, as well as related upgrades to the transmission system. A major portion of these costs are expected to be recovered through existing ratemaking provisions. The ultimate impact of environmental laws and regulations and the GHG goals discussed below will depend on various factors, such as state adoption and implementation of requirements, the availability and cost of any deployed control technology, and the outcome of pending and/or future legal challenges.

New or revised environmental laws and regulations could affect many areas of Alabama Power's operations. The impact of any such changes cannot be determined at this time. Environmental compliance costs could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Environmental compliance costs are recovered through Rate CNP Compliance. Further, increased 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. Additionally, many commercial and industrial customers may also be affected by existing and future environmental requirements, which for some may have the potential to ultimately affect their demand for electricity. 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" and "Retail Regulatory Matters – Rate CNP Compliance" in Item 8 of the Form 10-K for additional information.

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Environmental Laws and Regulations

Water Quality

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Water Quality" of Alabama Power in Item 7 of the Form 10-K for additional information regarding the effluent limitations guidelines (ELG) rule.

On May 2, 2018, the EPA updated its anticipated final rulemaking schedule for ELG from September 2020 to December 2019. The impact of any changes to the ELG rule will depend on the content of the final rule and the outcome of 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 Laws and Regulations – Coal Combustion Residuals" of Alabama Power in Item 7 of the Form 10-K for additional information regarding the Disposal of Coal Combustion Residuals from Electric Utilities rule (CCR Rule).

On July 30, 2018, the EPA published certain amendments to the CCR Rule, which will be effective August 29, 2018. These amendments extend the date from April 2019 to October 31, 2020 to cease sending CCR and other waste streams to impoundments that demonstrate compliance with all except two specified criteria. These amendments also establish groundwater protection standards for four constituents that do not have established EPA maximum contaminant levels and allow a participating state director or the EPA (where the EPA is the permitting authority) to suspend groundwater monitoring requirements under certain circumstances. Specific site impacts are being evaluated by Alabama Power.

On April 20, 2018, the Alabama Environmental Management Commission approved a state CCR rule that has been provided to the EPA for a six-month review period. This state CCR rule is generally consistent with the federal CCR Rule. The ultimate outcome of this matter cannot be determined at this time.

In June 2018, Alabama Power recorded an increase of approximately $1.2 billion to its AROs related to the CCR Rule. The revised cost estimates as of June 30, 2018 are based on information from feasibility studies performed on ash ponds in use at plants operated by Alabama Power. During the second quarter 2018, Alabama Power's management completed its analysis of these studies which indicated that additional closure costs, primarily related to increases in estimated ash volume, water management requirements, and design revisions, will be required to close these ash ponds under the planned closure-in-place methodology. As further analysis is performed and closure details are developed with respect to ash pond closures, Alabama Power expects to periodically update these cost estimates as necessary. See Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information.

Absent continued recovery of ARO costs through regulated rates, Alabama Power's results of operations, cash flows, and financial condition could be materially impacted. The ultimate outcome of these matters cannot be determined at this time.

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Nuclear Decommissioning

In June 2018, Alabama Power completed an updated decommissioning cost site study for Plant Farley. The estimated cost of decommissioning based on the study resulted in an increase in the ARO liability of approximately $300 million. Amounts previously contributed to the external trust funds are currently projected to be adequate to meet the updated decommissioning obligations. See Note 1 to the financial statements of Alabama Power under "Nuclear Decommissioning" in Item 8 of the Form 10-K and Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" and "Nuclear Decommissioning" herein for additional information.

Global Climate Issues

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues" of Alabama Power in Item 7 of the Form 10-K for additional information.

Through 2017, the Southern Company system has achieved an estimated GHG emission reduction of 36% since 2007. In April 2018, Southern Company established an intermediate goal of a 50% reduction in carbon emissions from 2007 levels by 2030 and a long-term goal of low- to no-carbon operations by 2050. To achieve these goals, the Southern Company system expects to continue growing its renewable energy portfolio, optimize technology advancements to modernize its transmission and distribution systems, increase the use of natural gas for generation, invest in energy efficiency, and continue research and development efforts focused on technologies to lower GHG emissions. The Southern Company system's ability to achieve these goals also will be dependent on many external factors, including supportive national energy policies, low natural gas prices, and the development, deployment, and advancement of relevant energy technologies. The ultimate outcome of this matter cannot be determined at this time.

FERC Matters

Market-Based Rate Authority

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters" of Alabama Power in Item 7 of the Form 10-K for additional information regarding proceedings related to the traditional electric operating companies' (including Alabama Power's) and Southern Power's 2014 and 2017 triennial market power analyses.

On May 4, 2018, the FERC issued an order terminating both proceedings, finding that the traditional electric operating companies (including Alabama Power) and Southern Power satisfy the FERC's standards for market-based rates. On May 9, 2018, the traditional electric operating companies (including Alabama Power) and Southern Power made the compliance filing required by the order. These proceedings are essentially concluded.

Open Access Transmission Tariff

On May 10, 2018, the Alabama Municipal Electric Authority and Cooperative Energy filed with the FERC a complaint against SCS and the traditional electric operating companies (including Alabama Power) claiming that the current 11.25% base ROE used in calculating the annual transmission revenue requirements of the traditional electric operating companies' (including Alabama Power's) open access transmission tariff is unjust and unreasonable as measured by the applicable FERC standards. The complaint requests that the base ROE be set no higher than 8.65% and that the FERC order refunds for the difference in revenue requirements that results from applying a just and reasonable ROE established in this proceeding upon determining the current ROE is unjust and unreasonable. On June 18, 2018, SCS and the traditional electric operating companies (including Alabama Power) filed their response challenging the adequacy of the showing presented by the complainants and offering support for the current ROE. The ultimate outcome of this matter cannot be determined at this time.

Relicensing of Hydroelectric Developments

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.

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On July 6, 2018, the U.S. Court of Appeals for the District of Columbia Circuit issued a decision vacating the FERC's 2013 order issuing a new 30-year license to Alabama Power for seven hydroelectric developments on the Coosa River and remanding the proceeding to the FERC for further proceedings. Alabama Power continues to operate the Coosa River developments under annual licenses issued by the FERC. 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 Rate RSE, Rate CNP, Rate ECR, and Rate NDR. 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 and Note (B) to the Condensed Financial Statements herein for additional information regarding Alabama Power's rate mechanisms, accounting orders, and the recovery balance of each regulatory clause for Alabama Power.

On May 1, 2018, the Alabama PSC approved modifications to Rate RSE and other commitments designed to position Alabama Power to address the growing pressure on its credit quality resulting from the Tax Reform Legislation, without increasing retail rates under Rate RSE in the near term. Alabama Power plans to reduce growth in total debt by increasing equity, with corresponding reductions in debt issuances, thereby de-leveraging its capital structure. Alabama Power's goal is to achieve an equity ratio of approximately 55% by the end of 2025. At June 30, 2018, Alabama Power's equity ratio was approximately 46.6%. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Federal Tax Reform Legislation" of Alabama Power in Item 7 of the Form 10-K for additional information.

Rate RSE

The approved modifications to Rate RSE became effective June 2018 and are applicable for January 2019 billings and thereafter. The modifications include reducing the top of the allowed weighted common equity return (WCER) range from 6.21% to 6.15% and modifications to the refund mechanism applicable to prior year actual results. The modifications to the refund mechanism allow Alabama Power to retain a portion of the revenue that causes the actual WCER for a given year to exceed the allowed range.

In conjunction with these modifications to Rate RSE, on May 8, 2018, Alabama Power consented to a moratorium on any upward adjustments under Rate RSE for 2019 and 2020. Additionally, Alabama Power will return $50 million to customers through bill credits in 2019.

In accordance with an established retail tariff that provides for an interim adjustment to customer billings to recognize the impact of a change in the statutory income tax rate, Alabama Power is returning approximately $257 million to retail customers through bill credits in the second half of 2018 as a result of the change in the federal income tax rate under the Tax Reform Legislation.

Rate ECR

On May 1, 2018, the Alabama PSC approved an increase to Rate ECR from 2.015 cents per KWH to 2.353 cents per KWH effective July 2018 which is expected to result in additional collections of approximately $100 million through December 31, 2018. The approved increase in the Rate ECR factor will have no significant effect on Alabama Power's net income, but will increase operating cash flows related to fuel cost recovery in 2018. The rate will return to 5.910 cents per KWH in 2019, absent a further order from the Alabama PSC.

Accounting Order

On May 1, 2018, the Alabama PSC approved an accounting order that authorizes Alabama Power to defer the benefits of federal excess deferred income taxes associated with the Tax Reform Legislation for the year ending December 31, 2018 as a regulatory liability and to use up to $30 million of such deferrals to offset under recovered

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amounts under Rate ECR. Any remaining amounts will be used for the benefit of customers as determined by the Alabama PSC. As of June 30, 2018, Alabama Power had applied approximately $30 million of such deferrals to offset the under recovered balance under Rate ECR and expects the total deferrals for the year ending December 31, 2018 to be approximately $50 million. See Note 5 to the financial statements of Alabama Power under "Federal Tax Reform Legislation" and "Current and Deferred Income Taxes" in Item 8 of the Form 10-K for additional information.

Plant Greene County

Alabama Power jointly owns Plant Greene County with an affiliate, Mississippi Power. See Note 4 to the financial statements of Alabama Power in Item 8 of the Form 10-K for additional information regarding the joint ownership agreement. On August 6, 2018, Mississippi Power filed its proposed Reserve Margin Plan (RMP) with the Mississippi PSC, which proposes a 4-year acceleration of the retirement of Plant Greene County Units 1 and 2 to the third quarter 2021 and the third quarter 2022, respectively. Mississippi Power's proposed Plant Greene County unit retirements would require the completion of proposed transmission and system reliability improvements, as well as agreement by Alabama Power. Alabama Power will monitor Mississippi Power's proposed RMP and associated regulatory process as well as the proposed transmission and system reliability improvements. Alabama Power will review all the facts and circumstances and will evaluate all its alternatives prior to reaching a final determination on the ongoing operations of Plant Greene County. The ultimate outcome of this matter cannot be determined at this time.

Income Tax Matters

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters" of Alabama Power in Item 7 of the Form 10-K and FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk," Note (B) to the Condensed Financial Statements under "Regulatory Matters – Alabama Power," and Note (H) to the Condensed Financial Statements herein for information regarding the Tax Reform Legislation and related regulatory actions.

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 laws and regulations governing air, water, land, and protection of natural resources. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental laws and regulations 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 or regulatory matters cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements herein, 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.

On March 2, 2018, the Alabama Department of Environmental Management (ADEM) issued proposed administrative orders assessing a penalty of $1.25 million to Alabama Power for unpermitted discharge of fluids and/or pollutants to groundwater at five electric generating plants. The proposed orders also require the submission to the ADEM of a plan with a schedule for implementation of a comprehensive groundwater investigation, including an assessment of corrective measures, a report evaluating any deficiencies at the facilities that may have led to the

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unpermitted discharges, and quarterly progress reports. Alabama Power is awaiting finalization of the orders. The ultimate outcome of this matter cannot be determined at this time.

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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

Recently Issued Accounting Standards

See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Recently Issued Accounting Standards" of Alabama Power in Item 7 of the Form 10-K for additional information regarding ASU No. 2016-02, Leases (Topic 842). See Note (A) to the Condensed Financial Statements herein for information regarding Alabama Power's recently adopted accounting standards.

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, 2018. Alabama Power intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.

Net cash provided from operating activities totaled $652 million for the first six months of 2018, a decrease of $20 million as compared to the first six months of 2017. The decrease in net cash provided from operating activities was primarily due to decreased fuel cost recovery and the timing of vendor payments. These uses of cash were partially offset by an increase in other current liabilities due to the timing of customer billing reductions related to the Tax Reform Legislation and income tax refunds in 2018. Net cash used for investing activities totaled $1.08 billion for the first six months of 2018 primarily due to gross property additions related to environmental, distribution, and transmission assets. Net cash provided from financing activities totaled $565 million for the first six months of 2018 primarily due to an issuance of long-term debt and additional capital contributions from Southern Company, partially offset by common stock dividend payments. Fluctuations in 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 2018 include increases of $2.1 billion in property, plant, and equipment primarily due to increases in AROs related to the CCR Rule and additions to distribution, environmental, and transmission assets, $1.4 billion in AROs related to the CCR Rule and nuclear decommissioning, $494 million in additional paid-in capital due to capital contributions from Southern Company, $294 million in long-term debt primarily due to the issuance of additional senior notes, and $200 million in securities due within one year reclassified from long-term debt. See Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information related to changes in Alabama Power's AROs.

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Capital Requirements and Contractual Obligations

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Alabama Power in Item 7 of the Form 10-K for a description of Alabama Power's capital requirements and contractual obligations. Approximately $200 million will be required through June 30, 2019 to fund maturities of long-term debt.

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

Alabama Power anticipates costs associated with closure-in-place and monitoring of ash ponds in accordance with the CCR Rule, which are reflected in Alabama Power's ARO liabilities. These costs, which are expected to change as Alabama Power continues to refine its assumptions underlying the cost estimates and evaluate the method and timing of compliance activities, are expected to begin in 2019 and are currently estimated to be approximately $232 million for 2019, $238 million for 2020, $246 million for 2021, and $252 million for 2022. See Note 1 to the financial statements of Alabama Power under "Asset Retirement Obligations and Other Costs of Removal" in Item 8 of the Form 10-K, FUTURE EARNINGS POTENTIAL – "Environmental Matters– Environmental Laws and Regulations – Coal Combustion Residuals" herein, and Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information.

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

Alabama Power's current liabilities sometimes exceed current assets because of 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, 2018, Alabama Power had approximately $686 million of cash and cash equivalents. Committed credit arrangements with banks at June 30, 2018 were as follows:

Expires												Expires Within One Year
2018		2019		2020		2022		Total		Unused		Term Out		No Term Out
(in millions)
$	2	$	31	$	500	$	800	$	1,333	$	1,333	$	—	$	33

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

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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. At June 30, 2018, Alabama Power was 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 programs. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support was approximately $854 million as of June 30, 2018. At June 30, 2018, Alabama Power had $120 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 traditional electric operating company under these arrangements are several and there is no cross-affiliate credit support. 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, 2018				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	$	—	—	%	$	44	2.2	%	$	245
Short-term bank loan	3		3.7	%	3		3.7	%	3
Total	$	3	3.7	%	$	47	2.3	%

(*) Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 2018.

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

Credit Rating Risk

At June 30, 2018, Alabama Power 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 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.

71

ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The maximum potential collateral requirements under these contracts at June 30, 2018 were as follows:

Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB and/or Baa2	$	1
At BBB- and/or Baa3	$	1
Below BBB- and/or Baa3	$	279

Included in these amounts are certain agreements that could require collateral in the event that either Alabama Power or Georgia Power (affiliate company of Alabama Power) 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.

As a result of the Tax Reform Legislation, certain financial metrics, such as the funds from operations to debt percentage, used by the credit rating agencies to assess Southern Company and its subsidiaries, including Alabama Power, may be negatively impacted. The modifications to Rate RSE and other commitments approved by the Alabama PSC are expected to help mitigate these potential adverse impacts to certain credit metrics and will help Alabama Power meet its goal of achieving an equity ratio of approximately 55% by the end of 2025. See Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Rate RSE" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Alabama Power – Rate RSE" herein for additional information.

Financing Activities

In June 2018, Alabama Power issued $500 million aggregate principal amount of Series 2018A 4.30% Senior Notes due July 15, 2048. The proceeds were used to repay outstanding commercial paper and for general corporate purposes, including Alabama Power's continuous construction program.

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.

72

GEORGIA POWER COMPANY

73

GEORGIA POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2018			2017			2018			2017
	(in millions)						(in millions)
Operating Revenues:
Retail revenues	$	1,889		$	1,904		$	3,688		$	3,593
Wholesale revenues, non-affiliates	36			40			80			79
Wholesale revenues, affiliates	3			9			13			17
Other revenues	120			95			227			191
Total operating revenues	2,048			2,048			4,008			3,880
Operating Expenses:
Fuel	378			445			790			815
Purchased power, non-affiliates	111			103			233			191
Purchased power, affiliates	178			138			349			310
Other operations and maintenance	457			417			863			816
Depreciation and amortization	230			223			458			444
Taxes other than income taxes	106			101			214			199
Estimated loss on Plant Vogtle Units 3 and 4	1,060			—			1,060			—
Total operating expenses	2,520			1,427			3,967			2,775
Operating Income (Loss)	(472		)	621			41			1,105
Other Income and (Expense):
Interest expense, net of amounts capitalized	(102		)	(104		)	(208		)	(205		)
Other income (expense), net	35			34			73			71
Total other income and (expense)	(67		)	(70		)	(135		)	(134		)
Earnings (Loss) Before Income Taxes	(539		)	551			(94		)	971
Income taxes (benefit)	(143		)	199			(50		)	355
Net Income (Loss)	(396		)	352			(44		)	616
Dividends on Preferred and Preference Stock	—			5			—			9
Net Income (Loss) After Dividends    on Preferred and Preference Stock	$	(396	)	$	347		$	(44	)	$	607

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended June 30,					For the Six Months Ended June 30,
	2018			2017		2018			2017
	(in millions)					(in millions)
Net Income (Loss)	$	(396	)	$	352	$	(44	)	$	616
Other comprehensive income (loss):
Qualifying hedges:
Reclassification adjustment for amounts included in net income, net of tax of $-, $-, $1, and $1, respectively	1			1		2			2
Total other comprehensive income (loss)	1			1		2			2
Comprehensive Income (Loss)	$	(395	)	$	353	$	(42	)	$	618

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

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GEORGIA POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Six Months Ended June 30,
	2018			2017
	(in millions)
Operating Activities:
Net income (loss)	$	(44	)	$	616
Adjustments to reconcile net income (loss) to net cash provided from operating activities —
Depreciation and amortization, total	562			543
Deferred income taxes	(256		)	159
Allowance for equity funds used during construction	(32		)	(25		)
Deferred expenses	34			41
Pension, postretirement, and other employee benefits	(47		)	(45		)
Settlement of asset retirement obligations	(49		)	(62		)
Estimated loss on Plant Vogtle Units 3 and 4	1,060			—
Other, net	27			(39		)
Changes in certain current assets and liabilities —
-Receivables	(103		)	(150		)
-Fossil fuel stock	38			(32		)
-Prepaid income taxes	115			(4		)
-Other current assets	25			(18		)
-Accounts payable	(87		)	(153		)
-Accrued taxes	(89		)	(194		)
-Accrued compensation	(56		)	(65		)
-Retail fuel cost over recovery	—			(84		)
-Other current liabilities	(26		)	(6		)
Net cash provided from operating activities	1,072			482
Investing Activities:
Property additions	(1,501		)	(1,284		)
Nuclear decommissioning trust fund purchases	(440		)	(271		)
Nuclear decommissioning trust fund sales	435			266
Cost of removal, net of salvage	(50		)	(32		)
Change in construction payables, net of joint owner portion	86			1
Payments pursuant to LTSAs	(46		)	(56		)
Asset dispositions	134			63
Other investing activities	(11		)	(12		)
Net cash used for investing activities	(1,393		)	(1,325		)
Financing Activities:
Increase in notes payable, net	480			37
Proceeds —
Capital contributions from parent company	1,502			380
Senior notes	—			850
Short-term borrowings	—			800
Redemptions and repurchases —
Senior notes	(1,000		)	(450		)
Pollution control revenue bonds	(398		)	(27		)
Short-term borrowings	(150		)	—
Other long-term debt	(100		)	—
Payment of common stock dividends	(691		)	(640		)
Premiums on redemption and repurchases of senior notes	(152		)	—
Other financing activities	(11		)	(19		)
Net cash provided from (used for) financing activities	(520		)	931
Net Change in Cash, Cash Equivalents, and Restricted Cash	(841		)	88
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	852			3
Cash, Cash Equivalents, and Restricted Cash at End of Period	$	11		$	91
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $12 and $11 capitalized for 2018 and 2017, respectively)	$	211		$	186
Income taxes, net	64			213
Noncash transactions — Accrued property additions at end of period	669			348

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

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GEORGIA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Assets	At June 30, 2018			At December 31, 2017
	(in millions)
Current Assets:
Cash and cash equivalents	$	11		$	852
Receivables —
Customer accounts receivable	631			544
Unbilled revenues	276			255
Under recovered fuel clause revenues	159			165
Joint owner accounts receivable	239			262
Affiliated	25			24
Other accounts and notes receivable	81			76
Accumulated provision for uncollectible accounts	(3		)	(3		)
Fossil fuel stock	276			314
Materials and supplies	498			504
Prepaid expenses	91			216
Other regulatory assets, current	206			205
Other current assets	23			14
Total current assets	2,513			3,428
Property, Plant, and Equipment:
In service	35,467			34,861
Less: Accumulated provision for depreciation	11,901			11,704
Plant in service, net of depreciation	23,566			23,157
Nuclear fuel, at amortized cost	536			544
Construction work in progress	4,157			4,613
Total property, plant, and equipment	28,259			28,314
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	52			53
Nuclear decommissioning trusts, at fair value	924			929
Miscellaneous property and investments	61			59
Total other property and investments	1,037			1,041
Deferred Charges and Other Assets:
Deferred charges related to income taxes	518			516
Other regulatory assets, deferred	3,064			2,932
Other deferred charges and assets	570			548
Total deferred charges and other assets	4,152			3,996
Total Assets	$	35,961		$	36,779

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

76

GEORGIA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholder's Equity	At June 30, 2018			At December 31, 2017
	(in millions)
Current Liabilities:
Securities due within one year	$	509		$	857
Notes payable	480			150
Accounts payable —
Affiliated	458			493
Other	885			834
Customer deposits	275			270
Accrued taxes	230			344
Accrued interest	110			123
Accrued compensation	149			219
Asset retirement obligations, current	191			270
Other regulatory liabilities, current	214			191
Other current liabilities	205			198
Total current liabilities	3,706			3,949
Long-term Debt	9,936			11,073
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	2,925			3,175
Deferred credits related to income taxes	3,218			3,248
Accumulated deferred ITCs	267			248
Employee benefit obligations	636			659
Asset retirement obligations, deferred	2,427			2,368
Other deferred credits and liabilities	144			128
Total deferred credits and other liabilities	9,617			9,826
Total Liabilities	23,259			24,848
Common Stockholder's Equity:
Common stock, without par value —
Authorized — 20,000,000 shares
Outstanding — 9,261,500 shares	398			398
Paid-in capital	8,834			7,328
Retained earnings	3,480			4,215
Accumulated other comprehensive loss	(10		)	(10		)
Total common stockholder's equity	12,702			11,931
Total Liabilities and Stockholder's Equity	$	35,961		$	36,779

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

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GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

SECOND QUARTER 2018 vs. SECOND QUARTER 2017

AND

YEAR-TO-DATE 2018 vs. YEAR-TO-DATE 2017

OVERVIEW

Georgia Power operates as a vertically integrated utility providing electric service 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 providing electric service. 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, stringent environmental standards, reliability, fuel, capital expenditures, and restoration following major storms. Georgia 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 Georgia Power for the foreseeable future. On April 3, 2018, the Georgia PSC approved a settlement agreement between Georgia Power and the staff of the Georgia PSC regarding the retail rate impact of the Tax Reform Legislation (Tax Reform Settlement Agreement). The Tax Reform Settlement Agreement provides for a total of $330 million in customer refunds for 2018 and 2019 and the deferral of certain revenues and tax benefits to be addressed in Georgia Power's next base rate case, which is expected to be filed by July 1, 2019. The Georgia PSC also approved an increase to Georgia Power's retail equity ratio to address the negative cash flow and credit metric impacts of the Tax Reform Legislation. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Rate Plans" herein for additional information on the Tax Reform Settlement Agreement.

Georgia Power continues to focus on several key performance indicators including, but not limited to, customer satisfaction, plant availability, system reliability, the execution of major construction projects, and net income.

Plant Vogtle Units 3 and 4 Status

In 2009, the Georgia PSC certified construction of Plant Vogtle Units 3 and 4 (with electric generating capacity of approximately 1,100 MWs each). In March 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. In December 2017, the Georgia PSC approved Georgia Power's recommendation to continue construction.

In the second quarter 2018, Georgia Power revised its base cost forecast and estimated contingency to complete construction and start-up of Plant Vogtle Units 3 and 4 to $8.0 billion and $0.4 billion, respectively, for a total project capital cost forecast of $8.4 billion (net of $1.7 billion received under the Guarantee Settlement Agreement and $188 million in Customer Refunds recognized as a regulatory liability in 2017). Although Georgia Power believes these incremental costs are reasonable and necessary to complete the project and the Georgia PSC has stated the $7.3 billion estimate included in the seventeenth VCM proceeding does not represent a cost cap, Georgia Power does not intend to seek rate recovery for the $0.7 billion increase in costs included in the revised base capital cost forecast, which will be filed with the Georgia PSC in the nineteenth VCM report on August 31, 2018. In connection with future VCM filings, Georgia Power may request the Georgia PSC to evaluate costs included in the revised construction contingency estimate for rate recovery as and when they are appropriately included in the base capital cost forecast. After considering the significant level of uncertainty that exists regarding the future recoverability of costs included in the construction contingency estimate since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in these future regulatory proceedings, Georgia Power has recorded a total pre-tax charge to income of $1.1 billion ($0.8 billion after tax) as of June 30, 2018.

78

GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

As a result of the increase in the total project capital cost forecast and Georgia Power's decision not to seek rate recovery of the increase in the base capital costs, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction. The Vogtle Owners are expected to conduct these votes in the third quarter 2018.

If the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 do not vote to continue construction, the Vogtle Joint Ownership Agreements provide that the project will be cancelled, and construction will cease. In the event that fewer than 90% of the Vogtle Owners vote to continue construction, Georgia Power and the other Vogtle Owners will assess options for Plant Vogtle Units 3 and 4. If Plant Vogtle Units 3 and 4 were cancelled and Georgia Power was unable to recover costs it has incurred in connection with the project, Georgia Power's results of operations, cash flow, and financial condition would be materially impacted. The ultimate outcome of this matter cannot be determined at this time.

Georgia Power's revised cost estimate reflects an expected in-service date of November 2021 for Unit 3 and November 2022 for Unit 4.

See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Nuclear Construction" and ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" herein for additional information on Plant Vogtle Units 3 and 4.

RESULTS OF OPERATIONS

Net Income (Loss)

Second Quarter 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$(743)	N/M	$(651)	N/M

N/M - Not meaningful

Georgia Power's net loss after dividends on preferred and preference stock for the second quarter 2018 was $396 million compared to net income after dividends on preferred and preference stock of $347 million for the corresponding period in 2017. For year-to-date 2018, net loss after dividends on preferred and preference stock was $44 million compared to net income after dividends on preferred and preference stock of $607 million for the corresponding period in 2017. The changes were primarily due to a $1.1 billion ($0.8 billion after tax) charge in the second quarter 2018 for an estimated probable loss related to Georgia Power's construction of Plant Vogtle Units 3 and 4, revenues deferred as a regulatory liability for future customer refunds related to the Tax Reform Legislation, and higher non-fuel operations and maintenance expenses. Partially offsetting the changes were lower federal income tax expense as a result of the Tax Reform Legislation and an increase in retail revenues associated with warmer weather in the second quarter 2018 compared to the corresponding period in 2017. Also offsetting the change for year-to-date 2018 was an increase in retail revenues associated with colder weather in the first quarter 2018 compared to the corresponding period in 2017. See Note (B) to the Condensed Financial Statements under "Nuclear Construction" herein for additional information on the estimated loss related to Georgia Power's construction of Plant Vogtle Units 3 and 4.

Retail Revenues

Second Quarter 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$(15)	(0.8)	$95	2.6

In the second quarter 2018, retail revenues were $1.89 billion compared to $1.90 billion for the corresponding period in 2017. For year-to-date 2018, retail revenues were $3.69 billion compared to $3.59 billion for the corresponding period in 2017.

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GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Details of the changes in retail revenues were as follows:

	Second Quarter 2018					Year-to-Date 2018
	(in millions)			(% change)		(in millions)			(% change)
Retail – prior year	$	1,904				$	3,593
Estimated change resulting from –
Rates and pricing	(58		)	(3.0	)	(108		)	(3.0	)
Sales growth	3			0.1		26			0.7
Weather	40			2.1		105			2.9
Fuel cost recovery	—			—		72			2.0
Retail – current year	$	1,889		(0.8	)%	$	3,688		2.6	%

Revenues associated with changes in rates and pricing decreased in the second quarter and year-to-date 2018 when compared to the corresponding periods in 2017 primarily due to revenues deferred as a regulatory liability for future customer refunds related to the Tax Reform Legislation and a decrease in revenues related to the recovery of Plant Vogtle Units 3 and 4 construction financing costs under the NCCR tariff, also primarily related to the Tax Reform Legislation. Also contributing to the year-to-date 2018 decrease was the rate pricing effect of increased customer usage in the first quarter 2018. The decreases were partially offset by higher contributions from variable demand-driven pricing from commercial and industrial customers. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Rate Plans" herein for additional information on regulatory actions related to the Tax Reform Legislation. Also, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Nuclear Construction" of Georgia Power in Item 7 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Nuclear Construction – Regulatory Matters" herein for additional information related to the NCCR tariff.

Revenues attributable to changes in sales increased in the second quarter and year-to-date 2018 when compared to the corresponding periods in 2017. Weather-adjusted residential KWH sales were essentially flat for the second quarter 2018 and increased 1.1% for year-to-date 2018 largely due to customer growth. Weather-adjusted commercial KWH sales increased 0.7% and 1.5% for the second quarter and year-to-date 2018, respectively, largely due to customer growth. Weather-adjusted industrial KWH sales increased slightly in the second quarter 2018 and increased 0.5% for year-to-date 2018, primarily due to increased demand in the stone, clay, and glass, rubber, and textiles sectors. The increase in weather-adjusted industrial KWH sales for year-to-date 2018 was partially offset by decreased demand in the paper sector.

Fuel revenues and costs are allocated between retail and wholesale jurisdictions. In the second quarter 2018, retail fuel cost recovery revenues remained flat when compared to the corresponding period in 2017 primarily due to increased energy sales driven by warmer weather and higher purchased power costs, largely offset by lower natural gas prices. For year-to-date 2018, retail fuel cost recovery revenues increased $72 million when compared to the corresponding period in 2017 primarily due to increased energy sales driven by colder weather in the first quarter 2018 and warmer weather in the second quarter 2018 and higher purchased power costs. Electric rates include provisions to periodically 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 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 additional information.

80

GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Wholesale Revenues – Affiliates

Second Quarter 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$(6)	(66.7)	$(4)	(23.5)

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

In the second quarter 2018, wholesale revenues from sales to affiliates were $3 million compared to $9 million for the corresponding period in 2017. For year-to-date 2018, wholesale revenues from sales to affiliates were $13 million compared to $17 million for the corresponding period in 2017. The decreases were due to 67.1% and 57.9% decreases in KWH sales in the second quarter and year-to-date 2018, respectively, primarily due to the higher cost of Georgia Power-owned generation as compared to the market cost of available energy.

Other Revenues

Second Quarter 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$25	26.3	$36	18.8

In the second quarter 2018, other revenues were $120 million compared to $95 million for the corresponding period in 2017. For year-to-date 2018, other revenues were $227 million compared to $191 million for the corresponding period in 2017. The increases were primarily due to $23 million and $38 million of revenues in the second quarter and year-to-date 2018, respectively, primarily from unregulated sales of products and services that were reclassified as other revenues as a result of the adoption of ASC 606, Revenue from Contracts with Customers (ASC 606). In prior periods, these revenues were included in other income (expense), net. See Note (A) to the Condensed Financial Statements herein for additional information regarding Georgia Power's adoption of ASC 606.

Fuel and Purchased Power Expenses

	Second Quarter 2018 vs. Second Quarter 2017					Year-to-Date 2018 vs. Year-to-Date 2017
	(change in millions)			(% change)		(change in millions)			(% change)
Fuel	$	(67	)	(15.1	)	$	(25	)	(3.1	)
Purchased power – non-affiliates	8			7.8		42			22.0
Purchased power – affiliates	40			29.0		39			12.6
Total fuel and purchased power expenses	$	(19	)			$	56

In the second quarter 2018, total fuel and purchased power expenses were $667 million compared to $686 million in the corresponding period in 2017. The decrease was primarily due to a $37 million decrease related to the average cost of fuel and purchased power primarily due to lower natural gas prices and a $49 million decrease related to the volume of KWHs generated due to scheduled generation outages, partially offset by an increase of $67 million related to the volume of KWHs purchased due to warmer weather.

For year-to-date 2018, total fuel and purchased power expenses were $1.37 billion compared to $1.32 billion in the corresponding period in 2017. The increase was primarily due to a $32 million increase related to the volume of KWHs generated and purchased due to colder weather in the first quarter 2018 and warmer weather in the second quarter 2018 and a $28 million increase related to the average cost of purchased power primarily due to higher

81

GEORGIA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

energy prices, partially offset by a $4 million decrease related to the average cost of fuel due to lower natural gas prices in the second quarter 2018.

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 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 additional information.

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

	Second Quarter 2018	Second Quarter 2017	Year-to-Date 2018	Year-to-Date 2017
Total generation (in billions of KWHs)	15	16	31	30
Total purchased power (in billions of KWHs)	8	6	14	13
Sources of generation (percent) —
Gas	40	37	42	41
Coal	29	36	29	32
Nuclear	28	25	26	25
Hydro	3	2	3	2
Cost of fuel, generated (in cents per net KWH)—
Gas	2.61	2.75	2.67	2.76
Coal	3.26	3.20	3.31	3.23
Nuclear	0.83	0.84	0.83	0.84
Average cost of fuel, generated (in cents per net KWH)	2.30	2.43	2.37	2.41
Average cost of purchased power (in cents per net KWH)(*)	4.37	4.76	4.81	4.61

(*) 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 2018, fuel expense was $378 million compared to $445 million in the corresponding period in 2017. The decrease was primarily due to a 9.3% decrease in the volume of KWHs generated largely due to scheduled generation outages and a 5.4% decrease in the average cost of fuel per KWH generated primarily due to lower natural gas prices.

For year-to-date 2018, fuel expense was $790 million compared to $815 million in the corresponding period in 2017. The decrease was primarily due to a 7.3% decrease in the volume of KWHs generated by coal largely due to scheduled generation outages and a 3.3% decrease in the average cost of fuel per KWH generated by natural gas, partially offset by a 2.5% increase in the average cost of fuel per KWH generated by coal.

Purchased Power – Non-Affiliates

In the second quarter 2018, purchased power expense from non-affiliates was $111 million compared to $103 million in the corresponding period in 2017. The increase was primarily due to a 3.6% increase in the average cost per KWH purchased primarily due to higher energy prices and a 1.9% increase in the volume of KWHs purchased primarily due to scheduled generation outages and warmer weather.

For year-to-date 2018, purchased power expense from non-affiliates was $233 million compared to $191 million in the corresponding period in 2017. The increase was primarily due to an 11.4% increase in the volume of KWHs purchased due to colder weather in the first quarter 2018, warmer weather in the second quarter 2018, and

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scheduled generation outages and a 10.5% increase in the average cost per KWH purchased due to higher energy 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 electric service territory, and the availability of the Southern Company system's generation.

Purchased Power – Affiliates

In the second quarter 2018, purchased power expense from affiliates was $178 million compared to $138 million in the corresponding period in 2017. The increase was primarily due to a 31.4% increase in the volume of KWHs purchased due to scheduled generation outages and warmer weather, partially offset by an 11.6% decrease in the average cost per KWH purchased primarily resulting from lower energy prices.

For year-to-date 2018, purchased power expense from affiliates was $349 million compared to $310 million in the corresponding period in 2017. The increase was primarily due to a 2.4% increase in the volume of KWHs purchased due to colder weather in the first quarter 2018 and scheduled generation outages and warmer weather in the second quarter 2018.

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 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$40	9.6	$47	5.8

In the second quarter 2018, other operations and maintenance expenses were $457 million compared to $417 million in the corresponding period in 2017. The increase was primarily due to $20 million of expenses from unregulated sales of products and services that were reclassified as other operations and maintenance expenses as a result of the adoption of ASC 606. In prior periods, these expenses were included in other income (expense), net. Also contributing to the increase were $8 million related to the timing of scheduled generation outage costs, $5 million primarily related to the timing of distribution overhead and underground line maintenance, $4 million in demand-side management costs related to the timing of new programs, and $3 million in billing adjustments with integrated transmission system owners, partially offset by a decrease of $7 million associated with an employee attrition plan.

For year-to-date 2018, other operations and maintenance expenses were $863 million compared to $816 million in the corresponding period in 2017. The increase was primarily due to $35 million of expenses from unregulated sales of products and services that were reclassified as other operations and maintenance expenses as a result of the adoption of ASC 606. In prior periods, these expenses were included in other income (expense), net. Also contributing to the increase were a $19 million decrease in gains from sales of integrated transmission system assets and an $11 million increase in demand-side management costs related to the timing of new programs, partially offset by decreases of $10 million related to affiliate labor billing adjustments and $6 million associated with an employee attrition plan.

See Note (A) to the Condensed Financial Statements herein for additional information regarding Georgia Power's adoption of ASC 606.

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Depreciation and Amortization

Second Quarter 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$7	3.1	$14	3.2

In the second quarter 2018, depreciation and amortization was $230 million compared to $223 million in the corresponding period in 2017. For year-to-date 2018, depreciation and amortization was $458 million compared to $444 million in the corresponding period in 2017. The increases were primarily due to increases of $8 million and $15 million related to additional plant in service in the second quarter and year-to-date 2018, respectively.

Taxes Other Than Income Taxes

Second Quarter 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$5	5.0	$15	7.5

In the second quarter 2018, taxes other than income taxes were $106 million compared to $101 million in the corresponding period in 2017. For year-to-date 2018, taxes other than income taxes were $214 million compared to $199 million in the corresponding period in 2017. The increases were primarily due to increases in property taxes of $4 million and $7 million in the second quarter and year-to-date 2018, respectively, as a result of an increase in the assessed value of property. Also contributing to the increase for year-to-date 2018 was a $7 million increase in municipal franchise fees largely related to higher retail revenues.

Estimated Loss on Plant Vogtle Units 3 and 4

Second Quarter 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$1,060	N/M	$1,060	N/M

N/M - Not meaningful

In the second quarter 2018, an estimated probable loss of $1.1 billion was recorded to reflect Georgia Power's revised estimate to complete construction and start-up of Plant Vogtle Units 3 and 4, which reflects the increase in costs included in the revised base capital cost forecast for which Georgia Power does not intend to seek rate recovery and costs included in the revised construction contingency estimate for which Georgia Power may seek rate recovery as and when such costs are appropriately included in the base capital cost forecast. See Note (B) to the Condensed Financial Statements under "Nuclear Construction" herein for additional information.

Income Taxes (Benefit)

Second Quarter 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$(342)	N/M	$(405)	N/M

N/M - Not meaningful

In the second quarter 2018, income tax benefit was $143 million compared to income tax expense of $199 million in the corresponding period in 2017. For year-to-date 2018, income tax benefit was $50 million compared to income tax expense of $355 million in the corresponding period in 2017. The changes were primarily due to the reduction in pre-tax earnings (loss) resulting from the estimated probable loss related to Plant Vogtle Units 3 and 4 and a lower federal income tax rate as a result of the Tax Reform Legislation. See Note (B) to the Condensed Financial Statements under "Nuclear Construction" herein for additional information on the estimated loss related to Georgia

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Power's construction of Plant Vogtle Units 3 and 4. Also, see Note (H) to the Condensed Financial Statements under "Effective Tax Rate" herein for additional information on the Tax Reform Legislation.

Dividends on Preferred and Preference Stock

Second Quarter 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$(5)	(100.0)	$(9)	(100.0)

In the second quarter and year-to-date 2018, there were no dividends on preferred and preference stock compared to $5 million and $9 million, respectively, in the corresponding periods in 2017. The decreases were due to the redemption in October 2017 of all outstanding shares of Georgia Power's preferred and preference stock. See Note 6 to the financial statements of Georgia Power under "Outstanding Classes of Capital 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 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 providing electric service. 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 limited projected demand growth over the next several years. Plant Vogtle Units 3 and 4 construction and rate recovery are also major factors. Future earnings will be driven primarily by customer growth. Earnings will also depend upon maintaining and growing sales, considering, among other things, the adoption and/or penetration rates of increasingly energy-efficient technologies, increasing volumes of electronic commerce transactions, and more multi-family home construction, all of which could contribute to a net reduction in customer usage. Earnings are subject to a variety of other 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 the pace of economic growth that may be affected by changes in regional and global economic conditions, which may impact future earnings.

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

Environmental Matters

Georgia Power's operations are regulated by state and federal environmental agencies through a variety of laws and regulations governing air, water, land, and protection of other natural resources. Georgia Power maintains comprehensive environmental compliance and greenhouse gas (GHG) strategies to assess upcoming requirements and compliance costs associated with these environmental laws and regulations. The costs, including capital expenditures and operations and maintenance costs, required to comply with environmental laws and regulations and to achieve stated goals may impact future unit retirement and replacement decisions, results of operations, cash flows, and financial condition. Related costs may result from the installation of additional environmental controls, closure and monitoring of CCR facilities, unit retirements, and adding or changing fuel sources for certain existing units, as well as related upgrades to the transmission system. A major portion of these costs are expected to be recovered through existing ratemaking provisions. The ultimate impact of environmental laws and regulations and the GHG goals discussed below will depend on various factors, such as state adoption and implementation of requirements, the availability and cost of any deployed control technology, and the outcome of pending and/or future legal challenges.

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New or revised environmental laws and regulations could affect many areas of Georgia Power's operations. The impact of any such changes cannot be determined at this time. Environmental compliance costs 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. Further, increased 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. Additionally, many commercial and industrial customers may also be affected by existing and future environmental requirements, which for some may have the potential to ultimately affect their demand for electricity. 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 Laws and Regulations

Water Quality

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Water Quality" of Georgia Power in Item 7 of the Form 10-K for additional information regarding the effluent limitations guidelines (ELG) rule.

On May 2, 2018, the EPA updated its anticipated final rulemaking schedule for ELG from September 2020 to December 2019. The impact of any changes to the ELG rule will depend on the content of the final rule and the outcome of 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 Laws and Regulations – Coal Combustion Residuals" of Georgia Power in Item 7 of the Form 10-K for additional information regarding the Disposal of Coal Combustion Residuals from Electric Utilities rule (CCR Rule).

On July 30, 2018, the EPA published certain amendments to the CCR Rule, which will be effective August 29, 2018. These amendments extend the date from April 2019 to October 31, 2020 to cease sending CCR and other waste streams to impoundments that demonstrate compliance with all except two specified criteria. These amendments also establish groundwater protection standards for four constituents that do not have established EPA maximum contaminant levels and allow a participating state director or the EPA (where the EPA is the permitting authority) to suspend groundwater monitoring requirements under certain circumstances. Specific site impacts are being evaluated by Georgia Power.

Georgia Power continues to perform engineering studies related to its plans to close the ash ponds at all of its generating plants, including one jointly owned with Gulf Power, in compliance with federal and state CCR rules. Georgia Power also continues to refine its closure strategy and cost estimates for each ash pond and is preparing permit applications as required by the State of Georgia CCR rule. While Georgia Power believes its recorded liability for ash pond closures appropriately reflects its obligations under the current closure strategies it has elected, changes to such strategies and cost estimates would likely result in additional closure costs which would increase Georgia Power's ARO liability. It is not currently possible to determine the magnitude of an increase related to a change in closure strategies nor an increase related to ongoing engineering studies for the current closure strategies, and the timing of future cash outflows are indeterminable at this time. As permit applications advance, engineering studies continue, and the timing of ash pond closures develop further on a plant-by-plant basis during the second half of 2018 and in the future, Georgia Power will record any changes as necessary to its ARO liability, which could be material. Georgia Power expects to continue to periodically update these cost estimates as necessary, which could change further as additional information becomes available. See Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information.

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Absent continued recovery of ARO costs through regulated rates, Georgia Power's results of operations, cash flows, and financial condition could be materially impacted.The ultimate outcome of these matters cannot be determined at this time.

Global Climate Issues

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues" of Georgia Power in Item 7 of the Form 10-K for additional information.

Through 2017, the Southern Company system has achieved an estimated GHG emission reduction of 36% since 2007. In April 2018, Southern Company established an intermediate goal of a 50% reduction in carbon emissions from 2007 levels by 2030 and a long-term goal of low- to no-carbon operations by 2050. To achieve these goals, the Southern Company system expects to continue growing its renewable energy portfolio, optimize technology advancements to modernize its transmission and distribution systems, increase the use of natural gas for generation, complete construction of Plant Vogtle Units 3 and 4, invest in energy efficiency, and continue research and development efforts focused on technologies to lower GHG emissions. The Southern Company system's ability to achieve these goals also will be dependent on many external factors, including supportive national energy policies, low natural gas prices, and the development, deployment, and advancement of relevant energy technologies. The ultimate outcome of this matter cannot be determined at this time.

FERC Matters

Market-Based Rate Authority

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters" of Georgia Power in Item 7 of the Form 10-K for additional information regarding proceedings related to the traditional electric operating companies' (including Georgia Power's) and Southern Power's 2014 and 2017 triennial market power analyses.

On May 4, 2018, the FERC issued an order terminating both proceedings, finding that the traditional electric operating companies (including Georgia Power) and Southern Power satisfy the FERC's standards for market-based rates. On May 9, 2018, the traditional electric operating companies (including Georgia Power) and Southern Power made the compliance filing required by the order. These proceedings are essentially concluded.

Open Access Transmission Tariff

On May 10, 2018, the Alabama Municipal Electric Authority and Cooperative Energy filed with the FERC a complaint against SCS and the traditional electric operating companies (including Georgia Power) claiming that the current 11.25% base ROE used in calculating the annual transmission revenue requirements of the traditional electric operating companies' (including Georgia Power's) open access transmission tariff is unjust and unreasonable as measured by the applicable FERC standards. The complaint requests that the base ROE be set no higher than 8.65% and that the FERC order refunds for the difference in revenue requirements that results from applying a just and reasonable ROE established in this proceeding upon determining the current ROE is unjust and unreasonable. On June 18, 2018, SCS and the traditional electric operating companies (including Georgia Power) filed their response challenging the adequacy of the showing presented by the complainants and offering support for the current ROE. The ultimate outcome of this matter cannot be determined at this time.

Retail Regulatory Matters

Georgia Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Georgia PSC. Georgia Power currently recovers its costs from the regulated retail business through the 2013 ARP, which includes traditional base tariff rates, Demand-Side Management tariffs, ECCR tariffs, and Municipal Franchise Fee tariffs. In addition, financing costs related to certified construction costs of Plant Vogtle Units 3 and 4 are being collected through the NCCR tariff and fuel costs are collected through a separate fuel cost recovery tariff. See "Nuclear Construction" herein and Note 3 to the financial statements of Georgia Power

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under "Retail Regulatory Matters – Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding the NCCR tariff. Also 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 additional information regarding fuel cost recovery.

Rate Plans

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Rate Plans" of Georgia Power in Item 7 of the Form 10-K for additional information regarding Georgia Power's 2013 ARP and the Georgia PSC's 2018 order related to the Tax Reform Legislation.

On April 3, 2018, the Georgia PSC approved the Tax Reform Settlement Agreement. Pursuant to the Tax Reform Settlement Agreement, to reflect the federal income tax rate reduction impact of the Tax Reform Legislation, Georgia Power will refund to customers a total of $330 million through bill credits of $131 million in October 2018, $96 million in June 2019, and $103 million in February 2020. In addition, Georgia Power is deferring as a regulatory liability (i) the revenue equivalent of the tax expense reduction resulting from legislation lowering the Georgia state income tax rate from 6.00% to 5.75% in 2019 and (ii) the entire benefit of approximately $700 million in federal and state excess accumulated deferred income taxes. The amortization of these regulatory liabilities is expected to be addressed in Georgia Power's next base rate case, which is scheduled to be filed by July 1, 2019. If there is not a base rate case in 2019, customers will receive $185 million in annual bill credits beginning in 2020, with any additional federal and state income tax savings deferred as a regulatory liability, until Georgia Power's next base rate case.

To address the negative cash flow and credit metric impacts of the Tax Reform Legislation, the Georgia PSC also approved an increase in Georgia Power's retail equity ratio to the lower of (i) Georgia Power's actual common equity weight in its capital structure or (ii) 55%, until Georgia Power's next base rate case. Benefits from reduced federal income tax rates in excess of the amounts refunded to customers will be retained by Georgia Power to cover the carrying costs of the incremental equity in 2018 and 2019.

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, VCM reports, and the NCCR tariff.

In 2009, the Georgia PSC certified construction of Plant Vogtle Units 3 and 4. In 2012, the NRC issued the related combined construction and operating licenses, which allowed full construction of the two AP1000 nuclear units (with electric generating capacity of approximately 1,100 MWs each) and related facilities to begin. Until March 2017, construction on Plant Vogtle Units 3 and 4 continued under the Vogtle 3 and 4 Agreement, which was a substantially fixed price agreement. In March 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code.

In connection with the EPC Contractor's bankruptcy filing, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into the Interim Assessment Agreement with the EPC Contractor to allow construction to continue. The Interim Assessment Agreement expired in July 2017 when Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the EPC Contractor entered into the Vogtle Services Agreement. Under the Vogtle Services Agreement, Westinghouse provides facility design and engineering services, procurement and technical support, and staff augmentation on a time and materials cost basis. The Vogtle Services Agreement will continue until the start-up and testing of Plant Vogtle Units 3 and 4 are complete and electricity is generated and sold from both units. The Vogtle Services Agreement is terminable by the Vogtle Owners upon 30 days' written notice.

In October 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into a construction completion agreement with Bechtel, whereby Bechtel will serve as the primary contractor for the remaining construction activities for Plant Vogtle Units 3 and 4 (Bechtel Agreement). The Bechtel Agreement is a

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cost reimbursable plus fee arrangement, whereby Bechtel is reimbursed for actual costs plus a base fee and an at-risk fee, which is subject to adjustment based on Bechtel's performance against cost and schedule targets. Each Vogtle Owner is severally (not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to Bechtel under the Bechtel Agreement. The Vogtle Owners may terminate the Bechtel Agreement at any time for their convenience, provided that the Vogtle Owners will be required to pay amounts related to work performed prior to the termination (including the applicable portion of the base fee), certain termination-related costs, and, at certain stages of the work, the applicable portion of the at-risk fee. Bechtel may terminate the Bechtel Agreement under certain circumstances, including certain Vogtle Owner suspensions of work, certain breaches of the Bechtel Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events. Pursuant to the Loan Guarantee Agreement between Georgia Power and the DOE, Georgia Power is required to obtain the DOE's approval of the Bechtel Agreement prior to obtaining any further advances under the Loan Guarantee Agreement.

In December 2017, the Georgia PSC approved Georgia Power's seventeenth VCM report, which included a recommendation to continue construction of Plant Vogtle Units 3 and 4, with Southern Nuclear serving as project manager and Bechtel serving as the primary construction contractor.

Cost and Schedule

In preparation for its nineteenth VCM filing, Georgia Power requested Southern Nuclear to perform a full cost reforecast for the project. Georgia Power's approximate proportionate share of the remaining estimated capital cost to complete Plant Vogtle Units 3 and 4 by the expected in-service dates of November 2021 and November 2022, respectively, is as follows:

	(in billions)
Base project capital cost forecast(a)(b)	$	8.0
Construction contingency estimate	0.4
Total project capital cost forecast(a)(b)	8.4
Net investment as of June 30, 2018(b)	(4.0		)
Remaining estimate to complete(a)	$	4.4

(a) Excludes financing costs expected to be capitalized through AFUDC of approximately $350 million.

(b) Net of $1.7 billion received from Toshiba in 2017 under the Guarantee Settlement Agreement and $188 million in Customer Refunds recognized as a regulatory liability in 2017.

Georgia Power estimates that its financing costs for construction of Plant Vogtle Units 3 and 4 will total approximately $3.2 billion, of which $1.7 billion had been incurred through June 30, 2018.

The $0.7 billion increase to the base capital cost forecast reflected in the table above primarily results from changed assumptions related to the finalization of contract scopes and management responsibilities for Bechtel and over 60 subcontractors, labor productivity rates, and craft labor incentives, as well as the related levels of project management, oversight, and support, including field supervision and engineering support.

Although Georgia Power believes these incremental costs are reasonable and necessary to complete the project and the Georgia PSC's order in the seventeenth VCM proceeding specifically states that the construction of Plant Vogtle Units 3 and 4 is not subject to a cost cap, Georgia Power does not intend to seek rate recovery for these cost increases included in the current base capital cost forecast (or any related financing costs), which will be filed with the Georgia PSC in the nineteenth VCM report at the end of August 2018. In connection with future VCM filings, Georgia Power may request the Georgia PSC to evaluate costs currently included in the construction contingency estimate for rate recovery as and when they are appropriately included in the base capital cost forecast. After considering the significant level of uncertainty that exists regarding the future recoverability of costs included in the construction contingency estimate since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in these future regulatory proceedings, Georgia

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Power has recorded a total pre-tax charge to income of $1.1 billion ($0.8 billion after tax), which includes the total increase in the capital cost forecast and construction contingency estimate as of June 30, 2018.

Subsequent to the EPC Contractor bankruptcy filing, a number of subcontractors to the EPC Contractor alleged non-payment by the EPC Contractor for amounts owed for work performed on Plant Vogtle Units 3 and 4. Georgia Power, acting for itself and as agent for the Vogtle Owners, has taken actions to remove liens filed by these subcontractors through the posting of surety bonds. Related to such liens, certain subcontractors have filed, and additional subcontractors may file, lawsuits against the EPC Contractor and the Vogtle Owners to preserve their payment rights with respect to such claims. All known amounts associated with the removal of subcontractor liens and other EPC Contractor pre-petition accounts payable have been paid or accrued as of June 30, 2018. The ultimate liability is expected to be finalized in connection with the completion of the sale of Westinghouse.

As construction continues, challenges with management of contractors, subcontractors, and vendors; labor productivity, availability, and/or cost escalation; procurement, fabrication, delivery, assembly, and/or installation, including any required engineering changes, of plant systems, structures, and components (some of which are based on new technology that is just beginning initial operation in the global nuclear industry at this scale); or other issues could arise and change the projected schedule and estimated cost.

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. 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, 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.

The ultimate outcome of these matters cannot be determined at this time. However, any extension of the project schedule is currently estimated to result in additional base capital costs of approximately $50 million per month, based on Georgia Power's ownership interests, and AFUDC of approximately $12 million per month. While Georgia Power is not precluded from seeking recovery of any future capital cost forecast increase, management will ultimately determine whether or not to seek recovery. Any further changes to the capital cost forecast that are not expected to be recoverable through regulated rates will be required to be charged to income and such charges could be material.

Joint Owner Contracts

In November 2017, the Vogtle Owners entered into an amendment to their joint ownership agreements for Plant Vogtle Units 3 and 4 (as amended, Vogtle Joint Ownership Agreements) to provide for, among other conditions, additional Vogtle Owner approval requirements. Pursuant to the Vogtle Joint Ownership Agreements, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction if certain adverse events occur, including: (i) the bankruptcy of Toshiba; (ii) termination or rejection in bankruptcy of certain agreements, including the Vogtle Services Agreement or the Bechtel Agreement; (iii) the Georgia PSC or Georgia Power determines that any of Georgia Power's costs relating to the construction of Plant Vogtle Units 3 and 4 will not be recovered in retail rates because such costs are deemed unreasonable or imprudent; or (iv) an increase in the construction budget contained in the seventeenth VCM report of more than $1 billion or extension of the project schedule contained in the seventeenth VCM report of more than one year. In addition, pursuant to the Vogtle Joint Ownership Agreements, the required approval of holders of ownership interests in Plant Vogtle Units 3 and 4 is at least (i) 90% for a change of the primary construction contractor and (ii) 67% for material amendments to the Vogtle Services Agreement or agreements with Southern Nuclear or the primary construction contractor, including the Bechtel Agreement. The Vogtle Joint Ownership Agreements also confirm that the Vogtle Owners' sole recourse against Georgia Power or Southern Nuclear for any action or inaction in connection with their performance as agent

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for the Vogtle Owners is limited to removal of Georgia Power and/or Southern Nuclear as agent, except in cases of willful misconduct.

As a result of the increase in the total project capital cost forecast and Georgia Power's decision not to seek rate recovery of the increase in the base capital costs as described in "Cost and Schedule" herein, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction. The Vogtle Owners are expected to conduct these votes in the third quarter 2018.

If the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 do not vote to continue construction, the Vogtle Joint Ownership Agreements provide that the project will be cancelled, and construction will cease. In the event that fewer than 90% of the Vogtle Owners vote to continue construction, Georgia Power and the other Vogtle Owners will assess options for Plant Vogtle Units 3 and 4. If Plant Vogtle Units 3 and 4 were cancelled and Georgia Power was unable to recover costs it has incurred in connection with the project, Georgia Power's results of operations, cash flow, and financial condition would be materially impacted. The ultimate outcome of this matter cannot be determined at this time.

Regulatory Matters

In 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4 with a certified capital cost of $4.418 billion. In addition, in 2009 the Georgia PSC approved inclusion of the Plant Vogtle Units 3 and 4 related CWIP accounts in rate base, and the State of Georgia enacted the Georgia Nuclear Energy Financing Act, which allows Georgia Power to recover financing costs for Plant Vogtle Units 3 and 4. Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff up to the certified capital cost of $4.418 billion. As of June 30, 2018, Georgia Power had recovered approximately $1.7 billion of financing costs. Financing costs related to capital costs above $4.418 billion will be recovered through AFUDC; however, Georgia Power will not record AFUDC related to any capital costs in excess of the total deemed reasonable by the Georgia PSC (currently $7.3 billion) and not requested for rate recovery.

Georgia Power is required to file semi-annual VCM reports with the Georgia PSC by February 28 and August 31 of each year. In 2013, in connection with the eighth VCM report, the Georgia PSC approved a stipulation between Georgia Power and the staff of the Georgia PSC to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate in accordance with the 2009 certification order until the completion of Plant Vogtle Unit 3, or earlier if deemed appropriate by the Georgia PSC and Georgia Power.

In 2016, the Georgia PSC voted to approve a settlement agreement (Vogtle Cost Settlement Agreement) resolving certain prudency matters in connection with the fifteenth VCM report. In December 2017, the Georgia PSC voted to approve (and issued its related order on January 11, 2018) certain recommendations made by Georgia Power in the seventeenth VCM report and modifying the Vogtle Cost Settlement Agreement. The Vogtle Cost Settlement Agreement, as modified by the January 11, 2018 order, resolved the following regulatory matters related to Plant Vogtle Units 3 and 4: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report should be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement was reasonable and prudent and none of the amounts paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) (a) capital costs incurred up to $5.68 billion would be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, (b) Georgia Power would have the burden to show that any capital costs above $5.68 billion were prudent, and (c) a revised capital cost forecast of $7.3 billion (after reflecting the impact of payments received under the Guarantee Settlement Agreement and Customer Refunds) was found reasonable; (iv) construction of Plant Vogtle Units 3 and 4 should be completed, with Southern Nuclear serving as project manager and Bechtel as primary contractor; (v) approved and deemed reasonable Georgia Power's revised schedule placing Plant Vogtle Units 3 and 4 in service in November 2021 and November 2022, respectively; (vi) confirmed that the revised cost forecast does not represent a cost cap and that prudence decisions on cost recovery will be made at a later date, consistent with applicable Georgia law; (vii) reduced the ROE used to calculate the NCCR tariff (a) from 10.95% (the ROE rate setting point authorized by the Georgia PSC in the 2013 ARP) to 10.00% effective January 1, 2016, (b) from 10.00% to 8.30%, effective January 1, 2020, and (c) from 8.30% to 5.30%, effective January 1, 2021

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(provided that the ROE in no case will be less than Georgia Power's average cost of long-term debt); (viii) reduced the ROE used for AFUDC equity for Plant Vogtle Units 3 and 4 from 10.00% to Georgia Power's average cost of long-term debt, effective January 1, 2018; and (ix) agreed that upon Unit 3 reaching commercial operation, retail base rates would be adjusted to include carrying costs on those capital costs deemed prudent in the Vogtle Cost Settlement Agreement. The January 11, 2018 order also stated that if Plant Vogtle Units 3 and 4 are not commercially operational by June 1, 2021 and June 1, 2022, respectively, the ROE used to calculate the NCCR tariff will be further reduced by 10 basis points each month (but not lower than Georgia Power's average cost of long-term debt) until the respective unit is commercially operational. The ROE reductions negatively impacted earnings by approximately $25 million in 2017 and are estimated to have negative earnings impacts of approximately $100 million in 2018 and an aggregate of $585 million from 2019 to 2022.

In its January 11, 2018 order, the Georgia PSC also stated if other conditions change and assumptions upon which Georgia Power's seventeenth VCM report are based do not materialize, the Georgia PSC reserved the right to reconsider the decision to continue construction.

On February 12, 2018, Georgia Interfaith Power & Light, Inc. and Partnership for Southern Equity, Inc. filed a petition appealing the Georgia PSC's January 11, 2018 order with the Fulton County Superior Court. On March 8, 2018, Georgia Watch filed a similar appeal to the Fulton County Superior Court for judicial review of the Georgia PSC's final decision and denial of Georgia Watch's motion for reconsideration. Georgia Power believes the two appeals have no merit; however, an adverse outcome in either appeal could have a material impact on Georgia Power's results of operations, financial condition, and liquidity.

The Georgia PSC has approved seventeen VCM reports covering the periods through June 30, 2017, including total construction capital costs incurred through that date of $4.4 billion. On August 21, 2018, the Georgia PSC is scheduled to vote on Georgia Power's eighteenth VCM report, which requested approval of $448 million of construction capital costs (excluding the $1.7 billion received from Toshiba under the Guarantee Settlement Agreement and the $188 million in Customer Refunds recognized as a regulatory liability) incurred from July 1, 2017 through December 31, 2017.

On August 31, 2018, Georgia Power will file its nineteenth VCM report with the Georgia PSC, which will reflect the revised capital cost forecast discussed previously and request approval of $578 million of construction capital costs incurred from January 1, 2018 through June 30, 2018.

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

See RISK FACTORS of Georgia Power in Item 1A herein and 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.

DOE Financing

As of June 30, 2018, Georgia Power had borrowed $2.6 billion related to Plant Vogtle Units 3 and 4 costs through the Loan Guarantee Agreement and a multi-advance credit facility among Georgia Power, the DOE, and the FFB, which provides for borrowings of up to $3.46 billion, subject to the satisfaction of certain conditions. In September 2017, the DOE issued a conditional commitment to Georgia Power for up to approximately $1.67 billion in additional guaranteed loans under the Loan Guarantee Agreement. In June 2018, the DOE approved a request by Georgia Power to extend the conditional commitment to September 30, 2018. Any further extension must be approved by the DOE. Final approval and issuance of these additional loan guarantees by the DOE cannot be assured and are subject to the negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions, including the Vogtle Owners' votes to continue construction. See Note 6 to the financial statements of Georgia Power under "DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements under "DOE Loan Guarantee Borrowings" herein for additional information, including applicable covenants, events of default, mandatory prepayment events (including any decision not to continue construction of Plant Vogtle Units 3 and 4), and conditions to borrowing.

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

Income Tax Matters

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters" of Georgia Power in Item 7 of the Form 10-K and FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk," Note (B) to the Condensed Financial Statements under "Regulatory Matters – Georgia Power," and Note (H) to the Condensed Financial Statements herein for information regarding the Tax Reform Legislation and related regulatory actions.

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 laws and regulations governing air, water, land, and protection of natural resources. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental laws and regulations 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 or regulatory matters cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Georgia Power's financial statements. See Note (B) to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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

Estimated Cost, Schedule, and Rate Recovery for the Construction of Plant Vogtle Units 3 and 4

In December 2016, the Georgia PSC approved the Vogtle Cost Settlement Agreement, which resolved certain prudency matters in connection with Georgia Power's fifteenth VCM report. In December 2017, the Georgia PSC approved Georgia Power's seventeenth VCM report, which included a recommendation to continue construction of Plant Vogtle Units 3 and 4, with Southern Nuclear serving as project manager and Bechtel serving as the primary construction contractor, as well as a modification of the Vogtle Cost Settlement Agreement. The Georgia PSC's related order stated that under the modified Vogtle Cost Settlement Agreement, (i) none of the $3.3 billion of costs incurred through December 31, 2015 should be disallowed as imprudent; (ii) capital costs incurred up to $5.68 billion would be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs; (iii) Georgia Power would have the burden of proof to show that any capital costs above $5.68 billion were prudent; (iv) Georgia Power's total project capital cost forecast of $7.3 billion (net of $1.7 billion received under the Guarantee Settlement Agreement and $188 million in Customer Refunds recognized as a regulatory liability in

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2017) was found reasonable and did not represent a cost cap; and (v) prudence decisions would be made subsequent to achieving fuel load for Unit 4.

In its order, the Georgia PSC also stated if other conditions change and assumptions upon which Georgia Power's seventeenth VCM report are based do not materialize, the Georgia PSC reserved the right to reconsider the decision to continue construction.

In the second quarter 2018, Georgia Power revised its base cost forecast and estimated contingency to complete construction and start-up of Plant Vogtle Units 3 and 4 to $8.0 billion and $0.4 billion, respectively, for a total project capital cost forecast of $8.4 billion (net of $1.7 billion received under the Guarantee Settlement Agreement and $188 million in Customer Refunds recognized as a regulatory liability in 2017). Although Georgia Power believes these incremental costs are reasonable and necessary to complete the project and the Georgia PSC has stated the $7.3 billion estimate included in the seventeenth VCM proceeding does not represent a cost cap, Georgia Power does not intend to seek rate recovery for the $0.7 billion increase in costs included in the revised base capital cost forecast, which will be filed with the Georgia PSC in the nineteenth VCM report on August 31, 2018. In connection with future VCM filings, Georgia Power may request the Georgia PSC to evaluate costs included in the revised construction contingency estimate for rate recovery as and when they are appropriately included in the base capital cost forecast. After considering the significant level of uncertainty that exists regarding the future recoverability of costs included in the construction contingency estimate since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in these future regulatory proceedings, Georgia Power has recorded a total pre-tax charge to income of $1.1 billion ($0.8 billion after tax) as of June 30, 2018.

Georgia Power's revised cost estimate reflects an expected in-service date of November 2021 for Unit 3 and November 2022 for Unit 4.

As construction continues, challenges with management of contractors, subcontractors, and vendors; labor productivity, availability, and/or cost escalation; procurement, fabrication, delivery, assembly, and/or installation, including any required engineering changes, of plant systems, structures, and components (some of which are based on new technology that is just beginning initial operation in the global nuclear industry at this scale); or other issues could arise and change the projected schedule and estimated cost.

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. 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, 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.

The ultimate outcome of these matters cannot be determined at this time. Any extension of the in-service dates of November 2021 for Unit 3 and November 2022 for Unit 4 is currently estimated to result in additional base capital costs of approximately $50 million per month, based on Georgia Power's ownership interests, and AFUDC of approximately $12 million per month. While Georgia Power is not precluded from seeking recovery of any future capital cost forecast increase, management will ultimately determine whether or not to seek recovery. Any further changes to the capital cost forecast that are not expected to be recoverable through regulated rates will be required to be charged to income and such charges could be material.

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Given the significant complexity involved in estimating the future costs to complete construction and start-up of Plant Vogtle Units 3 and 4 and the significant management judgment necessary to assess the related uncertainties surrounding future rate recovery of any projected cost increases, as well as the potential impact on Georgia Power's results of operations and cash flows, Georgia Power considers these items to be critical accounting estimates. 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 "Nuclear Construction" herein for additional information.

Recently Issued Accounting Standards

See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Recently Issued Accounting Standards" of Georgia Power in Item 7 of the Form 10-K for additional information regarding ASU No. 2016-02, Leases (Topic 842). See Note (A) to the Condensed Financial Statements herein for information regarding Georgia Power's recently adopted accounting standards.

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, 2018. 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 $1.07 billion for the first six months of 2018 compared to $482 million for the corresponding period in 2017. The increase was primarily due to increased fuel cost recovery, a decrease in current income taxes related to the Tax Reform Legislation, income tax refunds received, and the timing of fossil fuel stock purchases and property tax payments. Net cash used for investing activities totaled $1.39 billion for the first six months of 2018 primarily related to installation of equipment to comply with environmental standards and construction of generation, transmission, and distribution facilities. Net cash used for financing activities totaled $520 million for the first six months of 2018 primarily due to the redemption and repurchase of senior notes, payments of common stock dividends, and pollution control revenue bond purchases, partially offset by capital contributions 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 2018 include a decrease of $1.5 billion in long-term debt (including securities due within one year) primarily due to the redemption and repurchase of senior notes and the purchase of pollution control revenue bonds and an increase of $1.0 billion in property, plant, and equipment to comply with environmental standards and the construction of generation, transmission, and distribution facilities, including $0.6 billion related to the construction of Plant Vogtle Units 3 and 4. The increase in property, plant, and equipment was more than offset by a $1.1 billion decrease due to the charge related to the construction of Plant Vogtle Units 3 and 4. Total common stockholder's equity increased $0.8 billion primarily due to a $1.5 billion increase in paid-in capital resulting from capital contributions received from Southern Company, partially offset by a $0.7 billion decrease in retained earnings primarily due to the charge related to Plant Vogtle Units 3 and 4. See Note (B) to the Condensed Financial Statements under "Nuclear Construction" herein for additional information regarding Plant Vogtle Units 3 and 4.

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 and contractual obligations. Approximately $509 million will be required through June 30, 2019 to fund maturities of long-term debt. See "Sources of Capital" herein for additional

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information. Also see FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Nuclear Construction" for additional information regarding Plant Vogtle Units 3 and 4.

Georgia Power's construction program is currently estimated to total approximately $3.5 billion for 2018, $3.6 billion for 2019, $2.8 billion for 2020, $2.7 billion for 2021, and $2.4 billion for 2022. These amounts include expenditures of approximately $1.4 billion, $1.4 billion, $0.9 billion, $1.0 billion, and $0.6 billion for the construction of Plant Vogtle Units 3 and 4 in 2018, 2019, 2020, 2021, and 2022, respectively. These amounts also include capital expenditures related to contractual purchase commitments for nuclear fuel and capital expenditures covered under LTSAs. Estimated capital expenditures to comply with environmental laws and regulations included in these amounts are $0.5 billion, $0.1 billion, $0.2 billion, $0.2 billion, and $0.2 billion for 2018, 2019, 2020, 2021, and 2022, respectively. These estimated expenditures do not include any potential compliance costs associated with the regulation of CO₂ emissions from fossil fuel-fired electric generating units.

Georgia Power also anticipates costs associated with closure and monitoring of ash ponds in accordance with the CCR Rule, which are reflected in Georgia Power's ARO liabilities. These costs, which are expected to change as Georgia Power continues to refine its assumptions underlying the cost estimates and evaluate the method and timing of compliance activities, are estimated to be $0.2 billion per year for 2018 through 2020 and $0.3 billion per year for 2021 and 2022. For information regarding expected changes to these cost estimates during the second half of 2018, see FUTURE EARNINGS POTENTIAL – "Environmental Matters– Environmental Laws and Regulations – Coal Combustion Residuals" and Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein. Also see Note 1 to the financial statements of Georgia Power under "Asset Retirement Obligations and Other Costs of Removal" in Item 8 of the Form 10-K for additional information on AROs.

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 laws and regulations; the outcome of any legal challenges to environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing generating 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. The construction program also includes Plant Vogtle Units 3 and 4, which includes components based on new technology that is just beginning initial operation in the global nuclear industry at scale and which may be subject to additional revised cost estimates during construction. The ability to control costs and avoid cost and schedule overruns during the development, construction, and operation of new facilities is subject to a number of factors, including, but not limited to, changes in labor costs, availability, and productivity, challenges with management of contractors, subcontractors, or vendors, 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. 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 "Nuclear Construction" herein for information regarding additional factors that may impact construction expenditures.

Sources of Capital

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, external security issuances, borrowings from financial institutions, equity contributions from Southern Company, and borrowings from the FFB. However, the amount, type, and timing of any future financings, if needed, will depend upon regulatory approvals, prevailing market conditions, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL

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CONDITION AND LIQUIDITY – "Sources of Capital" of Georgia Power in Item 7 of the Form 10-K for additional information.

In 2014, Georgia Power entered into the Loan Guarantee Agreement with the DOE, under which the proceeds of borrowings 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. As of June 30, 2018, Georgia Power had borrowed $2.6 billion under the FFB Credit Facility. In July 2017, Georgia Power entered into an amendment to the Loan Guarantee Agreement, which provides that further advances are conditioned upon the DOE's approval of any agreements entered into in replacement of the Vogtle 3 and 4 Agreement and satisfaction of certain other conditions.

In September 2017, the DOE issued a conditional commitment to Georgia Power for up to approximately $1.67 billion of additional guaranteed loans under the Loan Guarantee Agreement. This conditional commitment expires on September 30, 2018, subject to any further extension approved by the DOE. Final approval and issuance of these additional loan guarantees by the DOE cannot be assured and are subject to the negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions, including the Vogtle Owners' votes to continue construction. See Note 6 to the financial statements of Georgia Power under "DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements under "DOE Loan Guarantee Borrowings" herein for additional information regarding the Loan Guarantee Agreement, including applicable covenants, events of default, mandatory prepayment events (including any decision not to continue construction of Plant Vogtle Units 3 and 4), and additional conditions to borrowing. Also see Note (B) to the Condensed Financial Statements under "Nuclear Construction" herein for additional information regarding Plant Vogtle Units 3 and 4.

At June 30, 2018, Georgia Power's current liabilities exceeded current assets by $1.2 billion primarily due to long-term debt that is due within one year of $509 million and notes payable of $480 million. Georgia Power's current liabilities frequently exceed current assets because of scheduled maturities of long-term debt and the periodic use of short-term debt as a funding source, as well as significant seasonal fluctuations in cash needs. Georgia Power intends to utilize operating cash flows, external security issuances, borrowings from financial institutions, equity contributions from Southern Company, and borrowings from the FFB 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, 2018, Georgia Power had approximately $11 million of cash and cash equivalents. Georgia Power's committed credit arrangement with banks at June 30, 2018 was $1.75 billion of which $1.74 billion was unused. This credit arrangement expires in 2022.

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. At June 30, 2018, Georgia Power was in compliance with this covenant. This bank credit arrangement does not contain a material adverse change clause at the time of borrowing.

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

See Note 6 to the financial statements of Georgia Power under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (F) 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

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outstanding requiring liquidity support as of June 30, 2018 was approximately $550 million. In addition, at June 30, 2018, Georgia Power had $232 million of pollution control revenue bonds outstanding that were required to be remarketed 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 traditional electric operating company under these arrangements are several and there is no cross-affiliate credit support. 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, 2018				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	$	480	2.4	%	$	120	2.3	%	$	495

(*) Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 2018.

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

Credit Rating Risk

At June 30, 2018, Georgia Power 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 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, interest rate management, and construction of new generation at Plant Vogtle Units 3 and 4.

The maximum potential collateral requirements under these contracts at June 30, 2018 were as follows:

Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB- and/or Baa3	$	87
Below BBB- and/or Baa3	$	1,020

Included in these amounts are certain agreements that could require collateral in the event that Georgia Power or Alabama Power (affiliate company of Georgia Power) has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of Georgia Power to access capital markets and would be likely to impact the cost at which it does so.

On February 28, 2018, Fitch downgraded the senior unsecured long-term debt rating of Georgia Power to A from A+ with a negative outlook.

As a result of the Tax Reform Legislation, certain financial metrics, such as the funds from operations to debt percentage, used by the credit rating agencies to assess Southern Company and its subsidiaries, including Georgia

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Power, may be negatively impacted. The Tax Reform Settlement Agreement approved by the Georgia PSC on April 3, 2018 is expected to help mitigate these potential adverse impacts to certain credit metrics by allowing a higher retail equity ratio until Georgia Power's next base rate case. See Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Rate Plans" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Georgia Power – Rate Plans" herein for additional information.

Financing Activities

In January 2018, Georgia Power repaid its outstanding $150 million and $100 million floating rate bank loans due May 31, 2018 and October 26, 2018, respectively.

In March 2018, Georgia Power purchased and held $104.6 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 2013 and $173 million aggregate principal amount of Development Authority of Bartow County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Bowen Project), First Series 2009. Georgia Power may reoffer these bonds to the public at a later date.

In April 2018, Georgia Power purchased and held $55 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Fifth Series 1994. Georgia Power may reoffer these bonds to the public at a later date.

Also in April 2018, Georgia Power redeemed all $250 million aggregate principal amount of its Series 2008B 5.40% Senior Notes due June 1, 2018.

In May 2018, through cash tender offers, Georgia Power repurchased and retired $89 million of the $250 million aggregate principal amount outstanding of its Series 2007A 5.65% Senior Notes due March 1, 2037, $326 million of the $500 million aggregate principal amount outstanding of its Series 2009A 5.95% Senior Notes due February 1, 2039, and $335 million of the $600 million aggregate principal amount outstanding of its Series 2010B 5.40% Senior Notes due June 1, 2040, for an aggregate purchase price, excluding accrued and unpaid interest, of $902 million.

In June 2018, Georgia Power purchased and held $65 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Second Series 2008. Georgia Power may reoffer these bonds to the public at a later date.

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

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CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2018			2017			2018			2017
	(in millions)						(in millions)
Operating Revenues:
Retail revenues	$	301		$	318		$	591		$	596
Wholesale revenues, non-affiliates	13			12			26			30
Wholesale revenues, affiliates	14			10			42			47
Other revenues	16			17			33			34
Total operating revenues	344			357			692			707
Operating Expenses:
Fuel	91			88			173			196
Purchased power	44			44			90			78
Other operations and maintenance	90			90			166			176
Depreciation and amortization	48			35			95			53
Taxes other than income taxes	28			28			58			55
Loss on Plant Scherer Unit 3	—			—			—			33
Total operating expenses	301			285			582			591
Operating Income	43			72			110			116
Other Income and (Expense):
Interest expense, net of amounts capitalized	(13		)	(13		)	(26		)	(24		)
Other income (expense), net	1			2			3			3
Total other income and (expense)	(12		)	(11		)	(23		)	(21		)
Earnings Before Income Taxes	31			61			87			95
Income taxes (benefit)	(11		)	24			3			38
Net Income	42			37			84			57
Dividends on Preference Stock	—			2			—			4
Net Income After Dividends on Preference Stock	$	42		$	35		$	84		$	53

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended June 30,					For the Six Months Ended June 30,
	2018		2017			2018		2017
	(in millions)					(in millions)
Net Income	$	42	$	37		$	84	$	57
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $-, $-, $-, and $(1), respectively	—		(1		)	—		(1		)
Total other comprehensive income (loss)	—		(1		)	—		(1		)
Comprehensive Income	$	42	$	36		$	84	$	56

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

101

GULF POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Six Months Ended June 30,
	2018			2017
	(in millions)
Operating Activities:
Net income	$	84		$	57
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	98			56
Deferred income taxes	(21		)	19
Loss on Plant Scherer Unit 3	—			33
Other, net	(3		)	(3		)
Changes in certain current assets and liabilities —
-Receivables	9			(25		)
-Other current assets	(2		)	14
-Accounts payable	(16		)	3
-Accrued taxes	18			7
-Accrued compensation	(15		)	(17		)
-Over recovered regulatory clause revenues	5			(19		)
-Other current liabilities	—			(1		)
Net cash provided from operating activities	157			124
Investing Activities:
Property additions	(135		)	(97		)
Cost of removal, net of salvage	(14		)	(9		)
Change in construction payables	(3		)	(14		)
Other investing activities	(6		)	(3		)
Net cash used for investing activities	(158		)	(123		)
Financing Activities:
Increase (decrease) in notes payable, net	45			(190		)
Proceeds —
Common stock issued to parent	—			175
Capital contributions from parent company	37			5
Senior notes	—			300
Redemptions —
Preference stock	—			(150		)
Senior notes	—			(85		)
Payment of common stock dividends	(77		)	(63		)
Other financing activities	(1		)	(4		)
Net cash provided from (used for) financing activities	4			(12		)
Net Change in Cash, Cash Equivalents, and Restricted Cash	3			(11		)
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	28			56
Cash, Cash Equivalents, and Restricted Cash at End of Period	$	31		$	45
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $- and $- capitalized for 2018 and 2017, respectively)	$	25		$	22
Income taxes, net	21			7
Noncash transactions — Accrued property additions at end of period	22			19

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

102

GULF POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Assets	At June 30, 2018			At December 31, 2017
	(in millions)
Current Assets:
Cash and cash equivalents	$	31		$	28
Receivables —
Customer accounts receivable	87			76
Unbilled revenues	71			67
Under recovered regulatory clause revenues	3			27
Affiliated	15			14
Other	5			7
Accumulated provision for uncollectible accounts	(1		)	(1		)
Fossil fuel stock	63			63
Materials and supplies	61			57
Other regulatory assets, current	49			56
Other current assets	19			21
Total current assets	403			415
Property, Plant, and Equipment:
In service	5,293			5,196
Less: Accumulated provision for depreciation	1,523			1,461
Plant in service, net of depreciation	3,770			3,735
Construction work in progress	116			91
Total property, plant, and equipment	3,886			3,826
Deferred Charges and Other Assets:
Deferred charges related to income taxes	30			31
Other regulatory assets, deferred	486			502
Other deferred charges and assets	36			23
Total deferred charges and other assets	552			556
Total Assets	$	4,841		$	4,797

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

103

GULF POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholder's Equity	At June 30, 2018			At December 31, 2017
	(in millions)
Current Liabilities:
Notes payable	$	90		$	45
Accounts payable —
Affiliated	51			52
Other	57			75
Customer deposits	35			35
Accrued taxes	28			10
Accrued interest	8			9
Accrued compensation	24			39
Deferred capacity expense, current	22			22
Asset retirement obligations, current	39			37
Other regulatory liabilities, current	54			—
Other current liabilities	24			27
Total current liabilities	432			351
Long-term Debt	1,285			1,285
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	540			537
Deferred credits related to income taxes	384			458
Employee benefit obligations	98			102
Deferred capacity expense	86			97
Asset retirement obligations, deferred	109			105
Other cost of removal obligations	216			221
Other regulatory liabilities, deferred	52			43
Other deferred credits and liabilities	64			67
Total deferred credits and other liabilities	1,549			1,630
Total Liabilities	3,266			3,266
Common Stockholder's Equity:
Common stock, without par value —
Authorized — 20,000,000 shares
Outstanding — 7,392,717 shares	678			678
Paid-in capital	632			594
Retained earnings	266			259
Accumulated other comprehensive loss	(1		)	—
Total common stockholder's equity	1,575			1,531
Total Liabilities and Stockholder's Equity	$	4,841		$	4,797

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

104

GULF POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

SECOND QUARTER 2018 vs. SECOND QUARTER 2017

AND

YEAR-TO-DATE 2018 vs. YEAR-TO-DATE 2017

OVERVIEW

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

On May 20, 2018, Southern Company entered into a stock purchase agreement with NextEra Energy to sell Gulf Power for an aggregate cash purchase price of $5.75 billion (less the amount of indebtedness assumed at closing, which is currently estimated at approximately $1.4 billion), subject to certain adjustments. The completion of the sale is subject to the satisfaction or waiver of certain closing conditions and is expected to occur in the first half of 2019. The ultimate outcome of this matter cannot be determined at this time. See Note (J) to the Condensed Financial Statements under "Southern Company's Sale of Gulf Power" herein for additional information.

Many factors affect the opportunities, challenges, and risks of Gulf Power's business of providing electric service. These factors include the ability to maintain a constructive regulatory environment, to maintain and grow energy sales and customers, and to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand growth, stringent environmental standards, reliability, restoration following major storms, fuel, and capital expenditures. Gulf 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 Gulf Power for the foreseeable future.

As a continuation of a settlement agreement approved by the Florida PSC in April 2017 (2017 Gulf Power Rate Case Settlement Agreement), on March 26, 2018, the Florida PSC approved a stipulation and settlement agreement among Gulf Power and three intervenors addressing the retail revenue requirement effects of the Tax Reform Legislation (Gulf Power Tax Reform Settlement Agreement).

The Gulf Power Tax Reform Settlement Agreement results in annual reductions to Gulf Power's revenues of $18.2 million from base rates and $15.6 million from environmental cost recovery rates, implemented April 1, 2018, and also provides for a one-time refund of $69.4 million for the retail portion of unprotected (not subject to normalization) deferred tax liabilities through a reduced fuel cost recovery rate over the remainder of 2018. Through June 30, 2018, approximately $28 million of this refund has been reflected in customer bills. As a result of the Gulf Power Tax Reform Settlement Agreement, the Florida PSC also approved an increase in Gulf Power's maximum equity ratio from 52.5% to 53.5% for all retail regulatory purposes.

As part of the Gulf Power Tax Reform Settlement Agreement, a limited scope proceeding to address protected deferred tax liabilities consistent with IRS normalization principles was initiated on April 30, 2018. Pending resolution of this proceeding, Gulf Power is deferring the related amounts for 2018 as a regulatory liability. Through June 30, 2018, amounts deferred totaled $5 million. Unless otherwise agreed to by the parties to the Gulf Power Tax Reform Settlement Agreement, amounts recorded in this regulatory liability will be refunded to retail customers in 2019 through Gulf Power's fuel cost recovery rates. The ultimate outcome of this matter cannot be determined at this time.

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

Gulf Power continues to focus on several key performance indicators including, but not limited to, customer satisfaction, plant availability, system reliability, and net income.

105

GULF POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

Net Income

Second Quarter 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$7	20.0	$31	58.5

Gulf Power's net income after dividends on preference stock for the second quarter 2018 was $42 million compared to $35 million for the corresponding period in 2017. The increase was primarily due to higher retail base revenues, partially offset by depreciation credits recognized in 2017. In addition, the increase in net income reflects lower federal income tax expense as a result of the Tax Reform Legislation, partially offset by a reduction in retail revenues related to the Gulf Power Tax Reform Settlement Agreement.

Gulf Power's net income after dividends on preference stock for year-to-date 2018 was $84 million compared to $53 million for the corresponding period in 2017. The increase was primarily due to higher retail base revenues and the first quarter 2017 write-down of $32.5 million ($20 million after tax) of Gulf Power's ownership of Plant Scherer Unit 3 in accordance with the 2017 Gulf Power Rate Case Settlement Agreement, partially offset by depreciation credits recognized in 2017. In addition, the increase in net income reflects lower federal income tax expense as a result of the Tax Reform Legislation, partially offset by a reduction in retail revenues related to the Gulf Power Tax Reform Settlement Agreement.

See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Retail Base Rate Cases" in Item 8 of the Form 10-K for additional information regarding the 2017 Gulf Power Rate Case Settlement Agreement.

Retail Revenues

Second Quarter 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$(17)	(5.3)	$(5)	(0.8)

In the second quarter 2018, retail revenues were $301 million compared to $318 million for the corresponding period in 2017. For year-to-date 2018, retail revenues were $591 million compared to $596 million for the corresponding period in 2017.

Details of the changes in retail revenues were as follows:

	Second Quarter 2018					Year-to-Date 2018
	(in millions)			(% change)		(in millions)			(% change)
Retail – prior year	$	318				$	596
Estimated change resulting from –
Rates and pricing	(20		)	(6.3	)	(15		)	(2.5	)
Sales growth	2			0.7		4			0.7
Weather	1			0.3		10			1.7
Fuel and other cost recovery	—			—		(4		)	(0.7	)
Retail – current year	$	301		(5.3	)%	$	591		(0.8	)%

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,

106

GULF POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 decreased in the second quarter and year-to-date 2018 when compared to the corresponding periods in 2017 primarily due to a decrease in revenues effective January 1, 2018 due to the Gulf Power Tax Reform Settlement Agreement, partially offset by an increase in retail base rates effective July 2017 in accordance with the 2017 Gulf Power Rate Case Settlement Agreement.

Revenues attributable to changes in sales increased in the second quarter 2018 when compared to the corresponding period in 2017. For the second quarter 2018, weather-adjusted KWH sales to residential customers increased 3.2% due to customer growth. Weather-adjusted KWH sales to commercial customers increased 1.0% due to customer growth, partially offset by lower energy usage resulting from energy efficiency improvements in appliances and lighting. KWH sales to industrial customers decreased 4.5% for the second quarter 2018 primarily due to changes in customers' operations.

Revenues attributable to changes in sales increased for year-to-date 2018 when compared to the corresponding period in 2017. For year-to-date 2018, weather-adjusted KWH sales to residential customers increased 2.7% due to customer growth. Weather-adjusted KWH sales to commercial customers increased 0.4% due to customer growth, partially offset by lower energy usage resulting from energy efficiency improvements in appliances and lighting. KWH sales to industrial customers decreased 0.7% year-to-date 2018 primarily due to changes in customers' operations.

Fuel and other cost recovery revenues remained essentially flat in the second quarter 2018 when compared to the corresponding period in 2017, primarily due to higher recoverable environmental costs, offset by lower recoverable costs under the purchased power capacity and fuel cost recovery clauses. Fuel and other cost recovery revenues decreased year-to-date 2018 when compared to the corresponding period in 2017, primarily due to lower recoverable costs under the purchased power capacity and fuel cost recovery clauses, partially offset by higher environmental recoverable costs. Fuel and other cost recovery provisions include fuel expenses, the energy component of purchased power costs, purchased power capacity costs, the difference between projected and actual costs and revenues related to energy conservation and environmental compliance, and a credit for certain wholesale revenues as a result of the 2017 Gulf Power Rate Case Settlement Agreement.

See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses" and " – Retail Base Rate Cases" in Item 8 of the Form 10-K for additional information regarding cost recovery clauses and the 2017 Gulf Power Rate Case Settlement Agreement, respectively. Also see FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Retail Base Rate Case" herein for additional information regarding the Gulf Power Tax Reform Settlement Agreement.

Wholesale Revenues – Non-Affiliates

Second Quarter 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$1	8.3	$(4)	(13.3)

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 the 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 electric service territory, and the availability of the Southern Company system's generation.

107

GULF POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

For year-to-date 2018, wholesale revenues from sales to non-affiliates were $26 million compared to $30 million for the corresponding period in 2017. The decrease was primarily due to a 24.7% decrease in KWH sales resulting from lower opportunity sales due to maintenance outages at Gulf Power generating units.

Wholesale Revenues – Affiliates

Second Quarter 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$4	40.0	$(5)	(10.6)

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

In the second quarter 2018, wholesale revenues from sales to affiliates were $14 million compared to $10 million for the corresponding period in 2017. The increase was primarily due to a 37.4% increase in KWH sales primarily resulting from increased generation to serve territorial load driven by the warm weather in June 2018.

For year-to-date 2018, wholesale revenues from sales to affiliates were $42 million compared to $47 million for the corresponding period in 2017. The decrease was primarily due to a 34.8% decrease in KWH sales primarily resulting from lower availability due to the first quarter 2018 planned outages at Gulf Power generating units. Partially offsetting this decrease was a 40.0% increase in the price of energy sold due to dispatching higher-priced generating resources driven by the colder weather in January 2018.

Fuel and Purchased Power Expenses

	Second Quarter 2018 vs. Second Quarter 2017			Year-to-Date 2018 vs. Year-to-Date 2017
	(change in millions)		(% change)	(change in millions)			(% change)
Fuel	$	3	3.4	$	(23	)	(11.7	)
Purchased power	—		—	12			15.4
Total fuel and purchased power expenses	$	3		$	(11	)

In the second quarter 2018, total fuel and purchased power expenses were $135 million compared to $132 million for the corresponding period in 2017. The increase was primarily the result of an $18 million increase related to the volume of KWHs generated and purchased, partially offset by a $15 million decrease related to the lower average cost of fuel and purchased power due to lower natural gas prices.

For year-to-date 2018, total fuel and purchased power expenses were $263 million compared to $274 million for the corresponding period in 2017. The decrease was primarily the result of a $20 million decrease related to the lower average cost of fuel and purchased power resulting from lower natural gas prices, partially offset by a $9 million net increase related to 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.

108

GULF POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

	Second Quarter 2018	Second Quarter 2017	Year-to-Date 2018	Year-to-Date 2017
Total generation (in millions of KWHs)	2,235	1,898	4,011	4,220
Total purchased power(in millions of KWHs)	1,359	1,218	2,981	2,676
Sources of generation (percent) –
Coal	56	50	48	52
Gas	44	50	52	48
Cost of fuel, generated (in cents per net KWH) –
Coal	3.21	3.17	3.18	3.23
Gas	3.40	3.88	3.17	3.54
Average cost of fuel, generated(in cents per net KWH)	3.29	3.53	3.18	3.38
Average cost of purchased power (in cents per net KWH)(*)	4.56	5.37	4.56	4.93

(*) 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 2018, fuel expense was $91 million compared to $88 million for the corresponding period in 2017. The increase was primarily due to a 17.8% increase in the volume of KWHs generated primarily to serve higher territorial load driven by the warm weather in June 2018.

For year-to-date 2018, fuel expense was $173 million compared to $196 million for the corresponding period in 2017. The decrease was primarily due to a 5.0% decrease in the volume of KWHs generated due to maintenance outages in 2018. Also contributing to the decrease was a 5.9% decrease in the average cost of fuel resulting from lower natural gas prices.

Purchased Power

In the second quarter 2018 and the corresponding period in 2017, purchased power expense was $44 million. The average cost of purchased power decreased 15.1% in the second quarter 2018 compared to the corresponding period in 2017 due to lower marginal natural gas prices, offset by an 11.6% increase in the volume of KWHs purchased due to higher territorial load.

For year-to-date 2018, purchased power expense was $90 million compared to $78 million for the corresponding period in 2017. The increase was primarily due to an 11.4% increase in the volume of KWHs purchased due to higher territorial load, partially offset by a 7.5% decrease in the average cost of purchased power due to lower natural gas prices.

Energy purchases from non-affiliates and 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 electric service territory, and the availability of the Southern Company system's generation. Affiliate purchases are made in accordance with the IIC or other contractual agreements, as approved by the FERC.

109

GULF POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Other Operations and Maintenance Expenses

Second Quarter 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$—	—	$(10)	(5.7)

In the second quarter 2018 and the corresponding period in 2017, other operations and maintenance expenses were $90 million. A decrease of $10 million in routine generation maintenance expenses was offset by a $10 million increase to the property damage reserve accrual.

For year-to-date 2018, other operations and maintenance expenses were $166 million compared to $176 million for the corresponding period in 2017. The decrease was primarily due to decreases of $11 million in routine generation maintenance expenses, including environmental expenditures, $4 million in energy service expenses, and $4 million in other operations and maintenance, primarily associated with vegetation management and employee benefits, partially offset by a $9 million increase to the property damage reserve accrual. See Note 1 to the financial statements of Gulf Power under "Property Damage Reserve" in Item 8 of the Form 10-K for additional information.

Expenses from energy services did not have a significant impact on earnings since they were generally offset by

associated revenues. Environmental compliance expenses did not have a significant impact on earnings since they were offset by environmental revenues through Gulf Power's environmental cost recovery clause. See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses – Environmental Cost Recovery" in Item 8 of the Form 10-K for additional information.

Depreciation and Amortization

Second Quarter 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$13	37.1	$42	79.2

In the second quarter 2018, depreciation and amortization was $48 million compared to $35 million for the corresponding period in 2017. For year-to-date 2018, depreciation and amortization was $95 million compared to $53 million for the corresponding period in 2017. The increases were primarily due to depreciation credits of $8.5 million and $34 million recognized in the second quarter and year-to-date 2017, respectively, as authorized in a settlement agreement approved by the Florida PSC in 2013. See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Retail Base Rate Cases" in Item 8 of the Form 10-K for additional information.

Loss on Plant Scherer Unit 3

Second Quarter 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$—	—	$(33)	N/M

N/M - Not meaningful

In the first quarter 2017, Gulf Power recorded a $32.5 million write-down related to its ownership of Plant Scherer Unit 3 in accordance with the 2017 Gulf Power Rate Case Settlement Agreement. See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Retail Base Rate Cases" in Item 8 of the Form 10-K for additional information.

110

GULF POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Income Taxes (Benefit)

Second Quarter 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$(35)	(145.8)	$(35)	(92.1)

In the second quarter 2018, income tax benefit was $11 million compared to tax expense of $24 million for the corresponding period in 2017. For year-to-date 2018, income taxes were $3 million compared to $38 million for the corresponding period in 2017. The changes were primarily due to the reduction in the federal income rate and the benefit from the flowback of excess deferred income taxes as a result of the Tax Reform Legislation as well as lower pre-tax earnings.

See Note (H) to the Condensed Financial Statements under "Effective Tax Rate" herein for additional information. Also see Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Retail Base Rate Cases" in Item 8 of the Form 10-K for more information regarding the 2017 Gulf Power Rate Case Settlement Agreement.

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 providing electric service. 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 and limited projected demand growth over the next several years. Future earnings will be driven primarily by customer growth. Earnings will also depend upon maintaining and growing sales, considering, among other things, the adoption and/or penetration rates of increasingly energy-efficient technologies due to changes in the minimum allowable equipment efficiencies along with the continuation of changes in customer behavior, both of which could contribute to a net reduction in customer usage. Earnings are subject to a variety of other 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, and the rate of economic growth or decline in Gulf Power's service territory. Demand for electricity is primarily driven by the pace of economic growth that 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.

On May 20, 2018, Southern Company entered into a stock purchase agreement with NextEra Energy to sell all of the capital stock of Gulf Power for an aggregate cash purchase price of $5.75 billion (less the amount of indebtedness assumed at closing, which is currently estimated at approximately $1.4 billion), subject to (i) customary adjustments for indebtedness and working capital and (ii) reduction by the amount (if any) by which Gulf Power fails to meet a specified capital expenditure target. The completion of the sale is subject to the satisfaction or waiver of certain closing conditions, including, among others, (i) the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act, (ii) approval by the FERC and the Federal Communications Commission, (iii) the entry into certain ancillary agreements, including transmission-related agreements and a transition services agreement, among the parties and their affiliates, and (iv) other customary closing conditions. The sale is expected to occur in the first half of 2019. See Note (J) to the Condensed Financial Statements under "Southern Company's Sale of Gulf Power" herein for additional information. The ultimate outcome of this matter cannot be determined at this time.

Environmental Matters

Gulf Power's operations are regulated by state and federal environmental agencies through a variety of laws and regulations governing air, water, land, and protection of other natural resources. Gulf Power maintains comprehensive environmental compliance and greenhouse gas (GHG) strategies to assess upcoming requirements

111

GULF POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

and compliance costs associated with these environmental laws and regulations. The costs, including capital expenditures and operations and maintenance costs, required to comply with environmental laws and regulations and to achieve stated goals may impact future unit retirement and replacement decisions, results of operations, cash flows, and financial condition. Related costs may result from the installation of additional environmental controls, closure and monitoring of CCR facilities, unit retirements, and adding or changing fuel sources for certain existing units, as well as related upgrades to the transmission system. A major portion of these costs are expected to be recovered through existing ratemaking provisions. The ultimate impact of environmental laws and regulations and the GHG goals discussed below will depend on various factors, such as state adoption and implementation of requirements, the availability and cost of any deployed control technology, and the outcome of pending and/or future legal challenges.

New or revised environmental laws and regulations could affect many areas of Gulf Power's operations. The impact of any such changes cannot be determined at this time. Environmental compliance costs could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis or through long-term wholesale agreements. 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. Further, increased 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. Additionally, many commercial and industrial customers may also be affected by existing and future environmental requirements, which for some may have the potential to ultimately affect their demand for electricity. 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, including a discussion on the State of Florida's statutory provisions on environmental cost recovery.

Environmental Laws and Regulations

Water Quality

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Water Quality" of Gulf Power in Item 7 of the Form 10-K for additional information regarding the effluent limitations guidelines (ELG) rule.

On May 2, 2018, the EPA updated its anticipated final rulemaking schedule for ELG from September 2020 to December 2019. The impact of any changes to the ELG rule will depend on the content of the final rule and the outcome of 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 Laws and Regulations – Coal Combustion Residuals" of Gulf Power in Item 7 of the Form 10-K for additional information regarding the Disposal of Coal Combustion Residuals from Electric Utilities rule (CCR Rule).

On July 30, 2018, the EPA published certain amendments to the CCR Rule, which will be effective August 29, 2018. These amendments extend the date from April 2019 to October 31, 2020 to cease sending CCR and other waste streams to impoundments that demonstrate compliance with all except two specified criteria. These amendments also establish groundwater protection standards for four constituents that do not have established EPA maximum contaminant levels and allow a participating state director or the EPA (where the EPA is the permitting authority) to suspend groundwater monitoring requirements under certain circumstances. Specific site impacts are being evaluated by Gulf Power.

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Georgia Power continues to perform engineering studies related to its plans to close the ash ponds at all of its generating plants, including Plant Scherer Unit 3 which is jointly owned with Gulf Power, in compliance with federal and state CCR rules. Georgia Power also continues to refine its closure strategy and cost estimates for each ash pond and is preparing permit applications as required by the State of Georgia CCR rule. While Gulf Power believes its recorded liability for ash pond closures appropriately reflects its obligations under the current closure strategy elected for Plant Scherer Unit 3, changes to such strategy and cost estimate would likely result in additional closure costs which would increase Gulf Power's ARO liability. It is not currently possible to determine the magnitude of an increase related to a change in closure strategy nor an increase related to ongoing engineering studies for the current closure strategy, and the timing of future cash outflows are indeterminable at this time. As permit applications advance, engineering studies continue, and the timing of the ash pond closure for Plant Scherer Unit 3 develops further during the second half of 2018 and in the future, Gulf Power will record any changes as necessary to its ARO liability, which could be material. Gulf Power expects to continue to periodically update these cost estimates as necessary, which could change further as additional information becomes available. See Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information.

Absent continued recovery of ARO costs through regulated rates, Gulf Power's results of operations, cash flows, and financial condition could be materially impacted.The ultimate outcome of these matters cannot be determined at this time.

Global Climate Issues

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues" of Gulf Power in Item 7 of the Form 10-K for additional information.

Through 2017, the Southern Company system has achieved an estimated GHG emission reduction of 36% since 2007. In April 2018, Southern Company established an intermediate goal of a 50% reduction in carbon emissions from 2007 levels by 2030 and a long-term goal of low- to no-carbon operations by 2050. To achieve these goals, the Southern Company system expects to continue growing its renewable energy portfolio, optimize technology advancements to modernize its transmission and distribution systems, increase the use of natural gas for generation, invest in energy efficiency, and continue research and development efforts focused on technologies to lower GHG emissions. The Southern Company system's ability to achieve these goals also will be dependent on many external factors, including supportive national energy policies, low natural gas prices, and the development, deployment, and advancement of relevant energy technologies. The ultimate outcome of this matter cannot be determined at this time.

FERC Matters

Market-Based Rate Authority

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters" of Gulf Power in Item 7 of the Form 10-K for additional information regarding proceedings related to the traditional electric operating companies' (including Gulf Power's) and Southern Power's 2014 and 2017 triennial market power analyses.

On May 4, 2018, the FERC issued an order terminating both proceedings, finding that the traditional electric operating companies (including Gulf Power) and Southern Power satisfy the FERC's standards for market-based rates. On May 9, 2018, the traditional electric operating companies (including Gulf Power) and Southern Power made the compliance filing required by the order. These proceedings are essentially concluded.

Open Access Transmission Tariff

On May 10, 2018, the Alabama Municipal Electric Authority and Cooperative Energy filed with the FERC a complaint against SCS and the traditional electric operating companies (including Gulf Power) claiming that the current 11.25% base ROE used in calculating the annual transmission revenue requirements of the traditional electric operating companies' (including Gulf Power's) open access transmission tariff is unjust and unreasonable as

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measured by the applicable FERC standards. The complaint requests that the base ROE be set no higher than 8.65% and that the FERC order refunds for the difference in revenue requirements that results from applying a just and reasonable ROE established in this proceeding upon determining the current ROE is unjust and unreasonable. On June 18, 2018, SCS and the traditional electric operating companies (including Gulf Power) filed their response challenging the adequacy of the showing presented by the complainants and offering support for the current ROE. The ultimate outcome of this matter 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. The recovery balance of each regulatory clause for Gulf Power is reported in Note (B) to the Condensed Financial Statements herein.

Retail Base Rate Case

As a continuation of the 2017 Gulf Power Rate Case Settlement Agreement, on March 26, 2018, the Florida PSC approved the Gulf Power Tax Reform Settlement Agreement.

The Gulf Power Tax Reform Settlement Agreement results in annual reductions to Gulf Power's revenues of $18.2 million from base rates and $15.6 million from environmental cost recovery rates, implemented April 1, 2018, and also provides for a one-time refund of $69.4 million for the retail portion of unprotected (not subject to normalization) deferred tax liabilities through a reduced fuel cost recovery rate over the remainder of 2018. Through June 30, 2018, approximately $28 million of this refund has been reflected in customer bills. As a result of the Gulf Power Tax Reform Settlement Agreement, the Florida PSC also approved an increase in Gulf Power's maximum equity ratio from 52.5% to 53.5% for all retail regulatory purposes.

As part of the Gulf Power Tax Reform Settlement Agreement, a limited scope proceeding to address protected deferred tax liabilities consistent with IRS normalization principles was initiated on April 30, 2018. Pending resolution of this proceeding, Gulf Power is deferring the related amounts for 2018 as a regulatory liability. Through June 30, 2018, amounts deferred totaled $5 million. Unless otherwise agreed to by the parties to the Gulf Power Tax Reform Settlement Agreement, amounts recorded in this regulatory liability will be refunded to retail customers in 2019 through Gulf Power's fuel cost recovery rates. The ultimate outcome of this matter cannot be determined at this time.

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

Income Tax Matters

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters" of Gulf Power in Item 7 of the Form 10-K and FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk," Note (B) to the Condensed Financial Statements under "Regulatory Matters – Gulf Power," and Note (H) to the Condensed Financial Statements herein for information regarding the Tax Reform Legislation and related regulatory actions.

Other Matters

Gulf Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Gulf Power is subject to certain claims and legal actions arising in the ordinary course of business. Gulf Power's business activities are subject to extensive governmental regulation related to public health and the environment, such as laws and regulations governing air, water, land, and protection of natural resources.

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Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental laws and regulations 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 or regulatory matters cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Gulf Power's financial statements. See Note (B) to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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

Recently Issued Accounting Standards

See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Recently Issued Accounting Standards" of Gulf Power in Item 7 of the Form 10-K for additional information regarding ASU No. 2016-02, Leases (Topic 842). See Note (A) to the Condensed Financial Statements herein for information regarding Gulf Power's recently adopted accounting standards.

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, 2018. 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 $157 million for the first six months of 2018 compared to $124 million for the corresponding period in 2017. The $33 million increase was primarily due to increased fuel cost recovery. Net cash used for investing activities totaled $158 million in the first six months of 2018 primarily due to property additions. Net cash provided from financing activities totaled $4 million for the first six months of 2018 primarily due to an increase in notes payable and capital contributions from Southern Company, partially offset by the payment of common stock dividends. 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 2018 include an increase of $60 million in property, plant, and equipment primarily due to additions at generation and distribution facilities; an increase of $54 million in other regulatory liabilities, current offset by a decrease of $74 million in deferred credits related to income taxes primarily as a result of the Gulf Power Tax Reform Settlement Agreement; and an increase of $45 million in notes payable related to commercial paper borrowings. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory

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Matters – Retail Base Rate Case" herein for additional information regarding the Gulf Power Tax Reform Settlement Agreement.

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 and contractual obligations. There are no scheduled maturities of long-term debt through June 30, 2019. 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 laws and regulations; the outcome of any legal challenges to environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing generating 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 to meet its future capital needs from sources similar to those used in the past, which were primarily from operating cash flows, external security issuances, borrowings from financial institutions, 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.

At June 30, 2018, Gulf Power's current liabilities exceeded current assets by $29 million. Gulf Power's current liabilities may exceed current assets because of scheduled maturities of long-term debt and the periodic use of short-term debt as a funding source, as well as significant seasonal fluctuations in cash needs.

Gulf Power intends to utilize operating cash flows, external security issuances, and borrowings from financial institutions to fund its short-term capital 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.

At June 30, 2018, Gulf Power had approximately $31 million of cash and cash equivalents. Committed credit arrangements with banks at June 30, 2018 were as follows:

Expires										Executable Term Loans		Expires Within One Year
2018		2019		2020		Total		Unused		One Year		Term Out		No Term Out
(in millions)
$	20	$	25	$	235	$	280	$	280	$	45	$	45	$	—

See Note 6 to the financial statements of Gulf Power under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (F) 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) 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. At June 30, 2018, Gulf Power was in compliance with all such covenants. A

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portion ($40 million) of the bank credit arrangements contain material adverse change clauses at the time of borrowings.

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

Most of the unused credit arrangements with banks are allocated to provide liquidity support to Gulf Power's pollution control revenue bonds and commercial paper program. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of June 30, 2018 was approximately $82 million. In addition, at June 30, 2018, Gulf Power had approximately $37 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 traditional electric operating company under these arrangements are several and there is no cross-affiliate credit support. Short-term borrowings are included in notes payable on the balance sheets.

Details of short-term borrowings were as follows:

	Short-term Debt at June 30, 2018				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	$	90	2.4	%	$	62	2.3	%	$	100

(*) Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 2018.

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

At June 30, 2018, Gulf Power 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 to BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, and energy price risk management.

The maximum potential collateral requirements under these contracts at June 30, 2018 were as follows:

Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB- and/or Baa3	$	117
Below BBB- and/or Baa3	$	418

Included in these amounts are certain agreements that could require collateral in the event that Alabama Power or Georgia Power (affiliate companies of Gulf Power) 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

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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.

On May 21, 2018, S&P revised its rating outlook for Gulf Power from negative to stable.

As a result of the Tax Reform Legislation, certain financial metrics, such as the funds from operations to debt percentage, used by the credit rating agencies to assess Southern Company and its subsidiaries, including Gulf Power, may be negatively impacted. The Gulf Power Tax Reform Settlement Agreement is expected to help mitigate these potential adverse impacts to Gulf Power's credit metrics by allowing a maximum equity ratio of 53.5% for all retail regulatory purposes. See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Gulf Power" herein for additional information.

Financing Activities

Gulf Power did not issue or redeem any securities during the six months ended June 30, 2018.

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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CONDENSED STATEMENTS OF OPERATIONS (UNAUDITED)

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2018			2017			2018			2017
	(in millions)						(in millions)
Operating Revenues:
Retail revenues	$	212		$	222		$	406		$	422
Wholesale revenues, non-affiliates	55			62			118			124
Wholesale revenues, affiliates	19			15			54			20
Other revenues	11			4			20			9
Total operating revenues	297			303			598			575
Operating Expenses:
Fuel	98			102			197			180
Purchased power	7			6			16			14
Other operations and maintenance	67			72			141			148
Depreciation and amortization	44			41			84			81
Taxes other than income taxes	27			26			54			52
Estimated loss on Kemper IGCC	—			3,012			45			3,120
Total operating expenses	243			3,259			537			3,595
Operating Income (Loss)	54			(2,956		)	61			(3,020		)
Other Income and (Expense):
Allowance for equity funds used during construction	—			36			—			71
Interest expense, net of amounts capitalized	(21		)	(17		)	(39		)	(37		)
Other income (expense), net	27			3			27			5
Total other income and (expense)	6			22			(12		)	39
Earnings (Loss) Before Income Taxes	60			(2,934		)	49			(2,981		)
Income taxes (benefit)	13			(881		)	9			(908		)
Net Income (Loss)	47			(2,053		)	40			(2,073		)
Dividends on Preferred Stock	1			1			1			1
Net Income (Loss) After Dividends on Preferred Stock	$	46		$	(2,054	)	$	39		$	(2,074	)

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (UNAUDITED)

	For the Three Months Ended June 30,					For the Six Months Ended June 30,
	2018		2017			2018			2017
	(in millions)					(in millions)
Net Income (Loss)	$	47	$	(2,053	)	$	40		$	(2,073	)
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $-, $-, $(1), and $-, respectively	—		—			(1		)	1
Reclassification adjustment for amounts included in net income, net of tax of $-, $-, $-, and $-, respectively	—		—			1			—
Total other comprehensive income (loss)	—		—			—			1
Comprehensive Income (Loss)	$	47	$	(2,053	)	$	40		$	(2,072	)

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,
	2018			2017
	(in millions)
Operating Activities:
Net income (loss)	$	40		$	(2,073	)
Adjustments to reconcile net income (loss) to net cash provided from operating activities —
Depreciation and amortization, total	86			94
Deferred income taxes	289			(860		)
Allowance for equity funds used during construction	—			(71		)
Estimated loss on Kemper IGCC	28			3,120
Other, net	(13		)	(11		)
Changes in certain current assets and liabilities —
-Receivables	(51		)	(15		)
-Fossil fuel stock	(2		)	21
-Other current assets	(9		)	(10		)
-Accounts payable	(15		)	(20		)
-Accrued taxes	(41		)	—
-Accrued compensation	(14		)	(17		)
-Over recovered regulatory clause revenues	10			(30		)
-Other current liabilities	(11		)	7
Net cash provided from operating activities	297			135
Investing Activities:
Property additions	(74		)	(337		)
Construction payables	(9		)	(19		)
Payments pursuant to LTSAs	(13		)	3
Other investing activities	(12		)	(8		)
Net cash used for investing activities	(108		)	(361		)
Financing Activities:
Decrease in notes payable, net	(4		)	(10		)
Proceeds —
Senior notes	600			—
Short-term borrowings	300			4
Capital contributions from parent company	1			1,001
Long-term debt to parent company	—			40
Redemptions —
Other long-term debt	(900		)	(300		)
Short-term borrowings	(200		)	—
Long-term debt to parent company	—			(591		)
Other financing activities	(6		)	(2		)
Net cash provided from (used for) financing activities	(209		)	142
Net Change in Cash, Cash Equivalents, and Restricted Cash	(20		)	(84		)
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	248			224
Cash, Cash Equivalents, and Restricted Cash at End of Period	$	228		$	140
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (paid $39 and $53, net of $- and $27 capitalized for 2018 and 2017, respectively)	$	39		$	26
Income taxes, net	(257		)	(93		)
Noncash transactions — Accrued property additions at end of period	23			59

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

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CONDENSED BALANCE SHEETS (UNAUDITED)

Assets	At June 30, 2018		At December 31, 2017
	(in millions)
Current Assets:
Cash and cash equivalents	$	228	$	248
Receivables —
Customer accounts receivable	37		36
Unbilled revenues	42		41
Income taxes receivable, current	37		4
Affiliated	21		16
Other accounts and notes receivable	24		12
Fossil fuel stock	19		17
Materials and supplies, current	50		44
Other regulatory assets, current	121		125
Other current assets	9		9
Total current assets	588		552
Property, Plant, and Equipment:
In service	4,816		4,773
Less: Accumulated provision for depreciation	1,365		1,325
Plant in service, net of depreciation	3,451		3,448
Construction work in progress	88		84
Total property, plant, and equipment	3,539		3,532
Other Property and Investments	25		30
Deferred Charges and Other Assets:
Deferred charges related to income taxes	34		35
Other regulatory assets, deferred	448		437
Accumulated deferred income taxes	—		247
Other deferred charges and assets	19		33
Total deferred charges and other assets	501		752
Total Assets	$	4,653	$	4,866

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

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CONDENSED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholder's Equity	At June 30, 2018			At December 31, 2017
	(in millions)
Current Liabilities:
Securities due within one year	$	257		$	989
Notes payable	100			4
Accounts payable —
Affiliated	53			59
Other	62			96
Accrued taxes —
Accrued income taxes	—			40
Other accrued taxes	51			101
Accrued compensation	25			39
Accrued plant closure costs	42			35
Asset retirement obligations, current	41			37
Other current liabilities	74			63
Total current liabilities	705			1,463
Long-term Debt	1,522			1,097
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	60			—
Deferred credits related to income taxes	415			372
Employee benefit obligations	112			116
Asset retirement obligations, deferred	135			137
Other cost of removal obligations	179			178
Other regulatory liabilities, deferred	78			79
Other deferred credits and liabilities	16			33
Total deferred credits and other liabilities	995			915
Total Liabilities	3,222			3,475
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	4,531			4,529
Accumulated deficit	(3,166		)	(3,205		)
Accumulated other comprehensive loss	(5		)	(4		)
Total common stockholder's equity	1,398			1,358
Total Liabilities and Stockholder's Equity	$	4,653		$	4,866

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

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SECOND QUARTER 2018 vs. SECOND QUARTER 2017

AND

YEAR-TO-DATE 2018 vs. YEAR-TO-DATE 2017

OVERVIEW

Mississippi Power operates as a vertically integrated utility providing electric service 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 providing electric service. 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 reliability, fuel, and stringent environmental standards, as well as ongoing capital and operations and maintenance expenditures and restoration following major storms. Appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Mississippi Power for the foreseeable future.

On July 27, 2018, Mississippi Power and the Mississippi Public Utilities Staff (MPUS) entered into a settlement agreement with respect to the 2018 PEP filing and all unresolved PEP filings for prior years (PEP Settlement Agreement), which was approved by the Mississippi PSC on August 7, 2018. Rates under the PEP Settlement Agreement, which result in approximately $21.6 million in additional revenue annually, will take effect for the first billing cycle of September 2018.

On August 3, 2018, Mississippi Power and the MPUS entered into a settlement agreement to increase rates approximately $17 million annually with respect to the 2018 ECO Plan filing (ECO Settlement Agreement), which was approved by the Mississippi PSC on August 7, 2018. Rates under the ECO Settlement Agreement will take effect for the first billing cycle of September 2018.

On May 8, 2018, the Mississippi PSC issued an order to begin an operations review of Mississippi Power in August 2018 with the final report expected by February 28, 2019. Mississippi Power expects that the review will include, but not be limited to, a comparative analysis of its costs, its cost recovery framework, and ways in which it may streamline management operations for the reasonable benefit of ratepayers. The ultimate outcome of this matter cannot be determined at this time.

See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters" herein for additional information.

As of June 30, 2018, Mississippi Power recorded charges to income of an immaterial amount for the second quarter 2018 and $45 million ($33 million after tax) for year-to-date 2018, primarily resulting from the abandonment and related closure activities for the mine and gasifier-related assets at the Kemper County energy facility. Additional closure costs for the mine and gasifier-related assets, currently estimated to cost up to $25 million pre-tax (excluding salvage, net of dismantlement costs), are expected to be incurred during the remainder of 2018 and 2019. In addition, period costs, including, but not limited to, costs for compliance and safety, ARO accretion, and property taxes for the mine and gasifier-related assets, are estimated at $4 million for the remainder of 2018, $7 million in 2019, and $4 million annually beginning in 2020. The ultimate outcome of this matter cannot be determined at this time.

On August 6, 2018, Mississippi Power filed its proposed Reserve Margin Plan (RMP), as required by the Mississippi PSC's order in the docket established for the purposes of pursuing a global settlement of the costs related to the Kemper County energy facility (Kemper Settlement Docket). Under the RMP, Mississippi Power proposes alternatives that would reduce its reserve margin, with the most economic of the alternatives being the2-year and 7-year acceleration of the retirement of Plant Watson Units 4 and 5, respectively, to the first quarter 2022 and the 4-year acceleration of the retirement of Plant Greene County Units 1 and 2 to the third quarter 2021 and the third quarter 2022, respectively, in order to lower or avoid operating costs. The Plant Greene County unit retirements would require the completion by Alabama Power of proposed transmission and system reliability

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improvements, as well as agreement by Alabama Power. The RMP filing also states that, in the event the Mississippi PSC ultimately approves an alternative that includes an accelerated retirement, Mississippi Power would require authorization to defer in a regulatory asset for future recovery the remaining net book value of the units at the time of retirement. Mississippi Power expects the MPUS and other interested parties to review the proposal prior to resolution by the Mississippi PSC. The ultimate outcome of this matter cannot be determined at this time. However, if approved by the Mississippi PSC, the alternatives are not expected to have any adverse impact on customer rates.

For additional information on the Kemper County energy facility, see Note 3 to the financial statements of Mississippi Power under "Kemper County Energy Facility" in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Kemper County Energy Facility" and Note (B) to the Condensed Financial Statements under "Kemper County Energy Facility" herein.

In March 2018, Mississippi Power issued $300 million aggregate principal amount of Series 2018A Floating Rate Senior Notes due March 27, 2020 bearing interest based on three-month LIBOR and $300 million aggregate principal amount of Series 2018B 3.95% Senior Notes due March 30, 2028. In March 2018, Mississippi Power also entered into a $300 million short-term floating rate bank loan bearing interest based on one-month LIBOR, of which $200 million was repaid in the second quarter 2018 and $50 million was repaid on July 31, 2018. Mississippi Power used the proceeds from these financings to repay a $900 million unsecured term loan.

Mississippi Power continues to focus on several key performance indicators. 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 ROE. Mississippi Power also focuses on broader measures of customer satisfaction, plant availability, system reliability, and net income after dividends on preferred stock.

RESULTS OF OPERATIONS

Net Income (Loss)

Second Quarter 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$2,100	N/M	$2,113	N/M

N/M - Not meaningful

Mississippi Power's net income after dividends on preferred stock for the second quarter 2018 was $46 million compared to a loss of $2.05 billion for the corresponding period in 2017. Mississippi Power's net income after dividends on preferred stock for year-to-date 2018 was $39 million compared to a loss of $2.07 billion for the corresponding period in 2017. The changes were related to lower pre-tax charges associated with the Kemper IGCC, slightly offset by the cessation of AFUDC equity related to the Kemper IGCC in the second quarter 2017.

See Note 3 to the financial statements of Mississippi Power under "Kemper County Energy Facility" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Kemper County Energy Facility" herein for additional information.

Retail Revenues

Second Quarter 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$(10)	(4.5)	$(16)	(3.8)

In the second quarter 2018, retail revenues were $212 million compared to $222 million for the corresponding period in 2017. For year-to-date 2018, retail revenues were $406 million compared to $422 million for the corresponding period in 2017.

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Details of the changes in retail revenues were as follows:

	Second Quarter 2018					Year-to-Date 2018
	(in millions)			(% change)		(in millions)			(% change)
Retail – prior year	$	222				$	422
Estimated change resulting from –
Rates and pricing	(7		)	(3.2	)	(14		)	(3.3	)
Sales decline	(2		)	(0.8	)	(2		)	(0.5	)
Weather	4			1.8		10			2.4
Fuel and other cost recovery	(5		)	(2.3	)	(10		)	(2.4	)
Retail – current year	$	212		(4.5	)%	$	406		(3.8	)%

Revenues associated with changes in rates and pricing decreased in the second quarter and year-to-date 2018 when compared to the corresponding periods in 2017 due to a reduction in base rates related to the Kemper County energy facility that became effective for the first billing cycle of April 2018 of $5 million and $6 million, respectively, and decreases of $2 million and $8 million, respectively, due to ECO Plan rates implemented in the second quarter 2017 related to the Plant Daniel Units 1 and 2 scrubbers. See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters – Environmental Compliance Overview Plan" and "Kemper County Energy Facility – Rate Recovery" in Item 8 of the Form 10-K for additional information.

Revenues attributable to changes in sales decreased for the second quarter and year-to-date 2018 compared to the corresponding periods in 2017. Weather-adjusted residential KWH sales were relatively flat in the second quarter and year-to-date 2018. Weather-adjusted commercial KWH sales decreased 2.8% and 1.6% for the second quarter and year-to-date 2018, respectively, primarily due to decreased customer usage related to energy efficiency, slightly offset by customer growth. Industrial KWH sales decreased 2.0% and 0.4% for the second quarter and year-to-date 2018, respectively, primarily due to decreased usage by several large industrial customers related to energy efficiency and optimization efforts.

Fuel and other cost recovery revenues decreased in the second quarter and year-to-date 2018 when compared to the corresponding periods in 2017 primarily as a result of lower recoverable fuel costs. 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 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$(7)	(11.3)	$(6)	(4.8)

Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Mississippi Power's and the Southern Company system's generation, demand for energy within the Southern Company system's electric 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.

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In the second quarter 2018, wholesale revenues from sales to non-affiliates were $55 million compared to $62 million for the corresponding period in 2017. For year-to-date 2018, wholesale revenues from sales to non-affiliates were $118 million compared to $124 million for the corresponding period in 2017. In the second quarter and year-to-date 2018, the decreases primarily resulted from a decrease in revenue under the Shared Services Agreement (SSA) of $5 million and $9 million, respectively, as a result of transmission revenue now being recovered under the Open Access Transmission Tariff (OATT). The year-to-date 2018 decrease was partially offset by an increase in sales due to weather.

Wholesale Revenues – Affiliates

Second Quarter 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$4	26.7	$34	N/M

N/M - Not meaningful

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 2018, wholesale revenues from sales to affiliates were $19 million compared to $15 million for the corresponding period in 2017. For year-to-date 2018, wholesale revenues from sales to affiliates were $54 million compared to $20 million for the corresponding period in 2017. These increases were primarily due to increases in KWH sales due to increased availability of Mississippi Power's lower cost generation resources to serve the Southern Company system's territorial load in 2018 as compared to 2017.

Other Revenues

Second Quarter 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$7	N/M	$11	N/M

N/M - Not meaningful

In the second quarter 2018, other revenues were $11 million compared to $4 million for the corresponding period in 2017. For year-to-date 2018, other revenues were $20 million compared to $9 million for the corresponding period in 2017. These increases were primarily due to increases in transmission revenue related to SSA customers now being recovered under the OATT.

Fuel and Purchased Power Expenses

	Second Quarter 2018 vs. Second Quarter 2017				Year-to-Date 2018 vs. Year-to-Date 2017
	(change in millions)			(% change)	(change in millions)		(% change)
Fuel	$	(4	)	(3.9)	$	17	9.4
Purchased power	1			16.7	2		14.3
Total fuel and purchased power expenses	$	(3	)		$	19

In the second quarter 2018, total fuel and purchased power expenses were $105 million compared to $108 million for the corresponding period in 2017. The decrease was primarily due to a $13 million decrease in the cost of

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natural gas and purchased power, partially offset by a $10 million increase in the volume of KWHs generated and purchased.

For year-to-date 2018, total fuel and purchased power expenses were $213 million compared to $194 million for the corresponding period in 2017. The increase was primarily due to a $28 million increase in the volume of KWHs generated and purchased, partially offset by a $10 million decrease in the cost of natural gas and purchased power.

Fuel and purchased power energy transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through Mississippi Power's fuel cost recovery clause.

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

	Second Quarter 2018	Second Quarter 2017	Year-to-Date 2018	Year-to-Date 2017
Total generation (in millions of KWHs)	4,081	3,927	8,084	7,088
Total purchased power (in millions of KWHs)(*)	238	121	433	362
Sources of generation (percent) –
Coal	7	7	6	8
Gas	93	93	94	92
Cost of fuel, generated (in cents per net KWH)–
Coal	3.42	3.61	3.49	3.46
Gas	2.51	2.73	2.56	2.69
Average cost of fuel, generated (in cents per net KWH)	2.58	2.79	2.61	2.76
Average cost of purchased power (in cents per net KWH)(*)	2.86	4.74	3.71	3.80

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

Fuel

In the second quarter 2018, total fuel expense was $98 million compared to $102 million for the corresponding period in 2017. The decrease was due to an 8.0% decrease in the cost of natural gas, partially offset by an increase in non-territorial sales as a result of lower prices.

For year-to-date 2018, total fuel expense was $197 million compared to $180 million for the corresponding period in 2017. The increase was due to a 14.9% increase in the volume of KWHs generated primarily as a result of higher sales, partially offset by a 5.0% decrease in the cost of natural gas.

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. 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 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$(5)	(6.9)	$(7)	(4.7)

In the second quarter 2018, other operations and maintenance expenses were $67 million compared to $72 million for the corresponding period in 2017. For year-to date 2018, other operations and maintenance expenses were $141 million compared to $148 million for the corresponding period in 2017. These decreases were primarily due to a

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reduction in professional services related to the combined cycle and associated common facilities portion of the Kemper County energy facility.

Depreciation and Amortization

Second Quarter 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$3	7.3	$3	3.7

In the second quarter 2018, depreciation and amortization was $44 million compared to $41 million for the corresponding period in 2017. The increase was primarily related to $4 million of depreciation for additional plant in service, partially offset by a $2 million decrease in amortization associated with regulatory assets and liabilities.

For year-to-date 2018, depreciation and amortization was $84 million compared to $81 million for the corresponding period in 2017. The increase was primarily related to $7 million of depreciation for additional plant in service, partially offset by a $4 million decrease in amortization associated with regulatory assets and liabilities.

Estimated Loss on Kemper IGCC

Second Quarter 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$(3,012)	(100.0)	$(3,075)	(98.6)

Estimated losses on the Kemper IGCC were immaterial for the second quarter 2018 and $45 million for year-to-date 2018, resulting from the abandonment and related closure activities for the mine and gasifier-related assets as compared to $3.01 billion and $3.12 billion for the corresponding periods in 2017 related to revisions to the estimated construction costs for, and subsequent suspension of, the Kemper IGCC in June 2017.

See Note 3 to the financial statements of Mississippi Power under "Kemper County Energy Facility" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Kemper County Energy Facility" herein for additional information.

Allowance for Equity Funds Used During Construction

Second Quarter 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$(36)	(100.0)	$(71)	(100.0)

In the second quarter and year-to-date 2018, AFUDC equity was immaterial compared to $36 million and $71 million, respectively, recorded for the corresponding periods in 2017 related to the Kemper IGCC construction. These decreases resulted from suspension of the Kemper IGCC construction in June 2017.

See Note 3 to the financial statements of Mississippi Power under "Kemper County Energy Facility" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Kemper County Energy Facility" herein for additional information.

Interest Expense, Net of Amounts Capitalized

Second Quarter 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$4	23.5	$2	5.4

In the second quarter 2018, interest expense, net of amounts capitalized was $21 million compared to $17 million for the corresponding period in 2017. For year-to-date 2018, interest expense, net of amounts capitalized was $39

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million compared to $37 million for the corresponding period in 2017. These increases were primarily due to reductions in AFUDC debt of $12 million and $24 million in the second quarter and year-to-date 2018, respectively, related to the Kemper IGCC project suspension in June 2017, largely offset by decreases in interest expense as a result of a decrease in average outstanding debt, the reversal of tax reserves in 2017, and decreases due to the completion of Kemper IGCC carrying cost amortization in 2017.

See Note 3 to the financial statements of Mississippi Power under "Kemper County Energy Facility" in Item 8 of the Form 10-K and Note (H) to the Condensed Financial Statements herein for additional information.

Other Income (Expense)

Second Quarter 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$24	N/M	$22	N/M

N/M - Not Meaningful

In the second quarter 2018, other income (expense), net was $27 million compared to $3 million for the corresponding period in 2017. For year-to-date 2018, other income (expense), net was $27 million compared to $5 million for the corresponding period in 2017. These increases were primarily due to the settlement of Mississippi Power's Deepwater Horizon claim in May 2018.

See Note (B) to the Condensed Financial Statements under "General Litigation Matters" herein.

Income Taxes (Benefit)

Second Quarter 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$894	N/M	$917	N/M

N/M - Not Meaningful

In the second quarter 2018, income taxes were $13 million compared to an income tax benefit of $881 million for the corresponding period in 2017. For year-to-date 2018, income taxes were $9 million compared to an income tax benefit of $908 million for the corresponding period in 2017. These changes were primarily due to lower estimated losses on the Kemper IGCC, net of the related non-deductible AFUDC equity in 2018 due to the Kemper IGCC project suspension in 2017. These increases also reflect increases resulting from higher pre-tax earnings, partially offset by the 2017 reversal of tax reserves related to research and experimental deductions and the impact of the Tax Reform Legislation.

See Note (H) 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 providing electric service. These factors include Mississippi Power's ability to recover its prudently-incurred costs in a timely manner during a time of increasing costs and limited projected demand growth over the next several years. Another factor is Mississippi Power's ability to prevail against legal challenges associated with the Kemper County energy facility. Future earnings will be driven primarily by customer growth. Earnings will also depend upon maintaining and growing sales, considering, among other things, the adoption and/or penetration rates of increasingly energy-efficient technologies and increasing volumes of electronic commerce transactions, both of which could contribute to a net reduction in customer usage. Earnings are subject to a variety of other 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

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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 the pace of economic growth that may be affected by changes in regional and global economic conditions, which may impact future earnings.

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

Environmental Matters

Mississippi Power's operations are regulated by state and federal environmental agencies through a variety of laws and regulations governing air, water, land, and protection of other natural resources. Mississippi Power maintains comprehensive environmental compliance and greenhouse gas (GHG) strategies to assess upcoming requirements and compliance costs associated with these environmental laws and regulations. The costs, including capital expenditures and operations and maintenance costs, required to comply with environmental laws and regulations and to achieve stated goals may impact future unit retirement and replacement decisions, results of operations, cash flows, and financial condition. Related costs may result from the installation of additional environmental controls, closure and monitoring of CCR facilities, unit retirements, and adding or changing fuel sources for certain existing units, as well as related upgrades to the transmission system. A major portion of these costs are expected to be recovered through existing ratemaking provisions. The ultimate impact of environmental laws and regulations and the GHG goals discussed below will depend on various factors, such as state adoption and implementation of requirements, the availability and cost of any deployed control technology, and the outcome of pending and/or future legal challenges.

New or revised environmental laws and regulations could affect many areas of Mississippi Power's operations. The impact of any such changes cannot be determined at this time. Environmental compliance costs could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis or through long-term wholesale agreements. Further, increased 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. Additionally, many commercial and industrial customers may also be affected by existing and future environmental requirements, which for some may have the potential to ultimately affect their demand for electricity. 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 Laws and Regulations

Water Quality

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Water Quality" of Mississippi Power in Item 7 of the Form 10-K for additional information regarding the effluent limitations guidelines (ELG) rule.

On May 2, 2018, the EPA updated its anticipated final rulemaking schedule for ELG from September 2020 to December 2019. The impact of any changes to the ELG rule will depend on the content of the final rule and the outcome of 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 Laws and Regulations – Coal Combustion Residuals" of Mississippi Power in Item 7 of the Form 10-K for additional information regarding the Disposal of Coal Combustion Residuals from Electric Utilities rule (CCR Rule).

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On July 30, 2018, the EPA published certain amendments to the CCR Rule, which will be effective August 29, 2018. These amendments extend the date from April 2019 to October 31, 2020 to cease sending CCR and other waste streams to impoundments that demonstrate compliance with all except two specified criteria. These amendments also establish groundwater protection standards for four constituents that do not have established EPA maximum contaminant levels and allow a participating state director or the EPA (where the EPA is the permitting authority) to suspend groundwater monitoring requirements under certain circumstances. Specific site impacts are being evaluated by Mississippi Power.

In June 2018, Mississippi Power recorded an increase of approximately $14 million to its AROs related to the CCR Rule. Approximately $11 million of the revised cost estimates as of June 30, 2018 are based on information from feasibility studies performed on an ash pond at a plant that is co-owned with Alabama Power. These studies indicated that additional closure costs, primarily related to increases in estimated ash volume, water management requirements, and design revisions, will be required to close the ash pond under the planned closure-in-place methodology. As further analysis is performed and closure details are developed, Mississippi Power expects to periodically update these cost estimates as necessary. See Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information.

Absent continued recovery of ARO costs through regulated rates, Mississippi Power's results of operations, cash flows, and financial condition could be materially impacted. The ultimate outcome of these matters cannot be determined at this time.

Global Climate Issues

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues" of Mississippi Power in Item 7 of the Form 10-K for additional information.

Through 2017, the Southern Company system has achieved an estimated GHG emission reduction of 36% since 2007. In April 2018, Southern Company established an intermediate goal of a 50% reduction in carbon emissions from 2007 levels by 2030 and a long-term goal of low- to no-carbon operations by 2050. To achieve these goals, the Southern Company system expects to continue growing its renewable energy portfolio, optimize technology advancements to modernize its transmission and distribution systems, increase the use of natural gas for generation, invest in energy efficiency, and continue research and development efforts focused on technologies to lower GHG emissions. The Southern Company system's ability to achieve these goals also will be dependent on many external factors, including supportive national energy policies, low natural gas prices, and the development, deployment, and advancement of relevant energy technologies. The ultimate outcome of this matter cannot be determined at this time.

FERC Matters

Municipal and Rural Association Tariff

See Note 3 to the financial statements of Mississippi Power under "FERC Matters – Municipal and Rural Associations Tariff" in Item 8 of the Form 10-K for additional information.

Mississippi Power expects to make an MRA filing in 2018. The ultimate outcome of this matter cannot be determined at this time.

Fuel Cost Recovery

Mississippi Power has a wholesale MRA and a Market Based (MB) fuel cost recovery factor. At June 30, 2018, the amount of over-recovered wholesale MRA fuel costs included in other regulatory liabilities, current on the condensed balance sheet was approximately $5 million compared to an immaterial amount at December 31, 2017. Under-recovered wholesale MB fuel costs included in the balance sheets were immaterial at June 30, 2018 and December 31, 2017.

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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

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters – Market-Based Rate Authority" of Mississippi Power in Item 7 of the Form 10-K for additional information regarding proceedings related to the traditional electric operating companies' (including Mississippi Power's) and Southern Power's 2014 and 2017 triennial market power analyses.

On May 4, 2018, the FERC issued an order terminating both proceedings, finding that the traditional electric operating companies (including Mississippi Power) and Southern Power satisfy the FERC's standards for market-based rates. On May 9, 2018, the traditional electric operating companies (including Mississippi Power) and Southern Power made the compliance filing required by the order. These proceedings are essentially concluded.

Cooperative Energy Power Supply Agreement

See Note 3 to the financial statements of Mississippi Power under "FERC Matters – Cooperative Energy Power Supply Agreement" in Item 8 of the Form 10-K for additional information regarding Cooperative Energy's network integration transmission service agreement (NITSA) with SCS.

On March 23, 2018, the FERC accepted the amendment to the NITSA between Cooperative Energy and SCS, effective April 1, 2018.

Open Access Transmission Tariff

On May 10, 2018, the Alabama Municipal Electric Authority and Cooperative Energy filed with the FERC a complaint against SCS and the traditional electric operating companies (including Mississippi Power) claiming that the current 11.25% base ROE used in calculating the annual transmission revenue requirements of the traditional electric operating companies' (including Mississippi Power's) open access transmission tariff is unjust and unreasonable as measured by the applicable FERC standards. The complaint requests that the base ROE be set no higher than 8.65% and that the FERC order refunds for the difference in revenue requirements that results from applying a just and reasonable ROE established in this proceeding upon determining the current ROE is unjust and unreasonable. On June 18, 2018, SCS and the traditional electric operating companies (including Mississippi Power) filed their response challenging the adequacy of the showing presented by the complainants and offering support for the current ROE. The ultimate outcome of this matter cannot be determined at this time.

Retail Regulatory Matters

Mississippi Power's rates and charges for service to retail customers are subject to the regulatory oversight of the Mississippi PSC. Mississippi Power's rates are a combination of base rates under PEP 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 expected to be recovered through Mississippi Power's base rates.

On May 8, 2018, the Mississippi PSC issued an order to begin an operations review of Mississippi Power in August 2018 with the final report expected by February 28, 2019. Mississippi Power expects that the review will include, but not be limited to, a comparative analysis of its costs, its cost recovery framework, and ways in which it may streamline management operations for the reasonable benefit of ratepayers. The ultimate outcome of this matter cannot be determined at this time.

See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters" and "Kemper County Energy Facility" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Mississippi Power" herein for additional information.

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Performance Evaluation Plan

On February 7, 2018, Mississippi Power submitted its revised 2018 projected PEP filing to the Mississippi PSC, which reflected the impacts of the Tax Reform Legislation, requesting an increase in annual retail revenues of $26 million based on a performance adjusted ROE of 9.33% and an increased equity ratio of 55%.

On March 22, 2018, Mississippi Power submitted its annual PEP lookback filing for 2017, which reflected no surcharge or refund.

On July 27, 2018, Mississippi Power and the MPUS entered into the PEP Settlement Agreement, which was approved by the Mississippi PSC on August 7, 2018. Rates under the PEP Settlement Agreement will take effect for the first billing cycle of September 2018.

The PEP Settlement Agreement provides for an increase of approximately $21.6 million in annual base retail revenues, which excludes approximately $5.5 million requested for certain compensation costs contested by the MPUS. Under the PEP Settlement Agreement, Mississippi Power expects to defer these costs for 2018 and 2019 as a regulatory asset. The Mississippi PSC is currently expected to rule on the appropriate treatment for such costs in connection with Mississippi Power's next base rate case, which is scheduled to be filed in the fourth quarter 2019 (2019 Base Rate Case). The ultimate outcome of this matter cannot be determined at this time.

Pursuant to the PEP Settlement Agreement, Mississippi Power's performance-adjusted allowed ROE will be 9.31% and its allowed equity ratio will remain at 50%, pending further review by the Mississippi PSC. In lieu of the requested equity ratio increase, Mississippi Power will retain $44 million of excess accumulated deferred income taxes resulting from the Tax Reform Legislation, which had been proposed to be amortized beginning in 2018, until the conclusion of the 2019 Base Rate Case. Further, Mississippi Power will seek equity contributions sufficient to restore its equity ratio (which was 43.5% at June 30, 2018) to the 50% target. In the event Mississippi Power's actual average equity ratio for 2018 is more than 1% higher or lower than the 50% target, Mississippi Power will defer the corresponding difference in its revenue requirement as a regulatory asset or liability for resolution in the 2019 Base Rate Case.

Pursuant to the PEP Settlement Agreement, PEP proceedings will be suspended until after the conclusion of the 2019 Base Rate Case and Mississippi Power will not be required to make any PEP filings for regulatory years 2018, 2019, and 2020. The PEP Settlement Agreement also resolves all open PEP filings with no change to customer rates. As a result, in the third quarter 2018, Mississippi Power expects to recognize revenues of $5 million previously reserved in connection with the 2012 PEP lookback filing.

Energy Efficiency

On May 8, 2018, the Mississippi PSC issued an order approving Mississippi Power's revised annual projected Energy Efficiency Cost Rider 2018 compliance filing, submitted on May 3, 2018, which increased annual retail revenues by approximately $3 million effective with the first billing cycle for June 2018.

Environmental Compliance Overview Plan

On August 3, 2018, Mississippi Power and the MPUS entered into the ECO Settlement Agreement, which provides for an increase of approximately $17 million in annual base retail revenues and was approved by the Mississippi PSC on August 7, 2018. Rates under the ECO Settlement Agreement will take effect for the first billing cycle of September 2018 and will continue in effect until modified by the Mississippi PSC. These revenues are expected to be sufficient to recover the costs included in Mississippi Power's request for 2018, as well as the remaining deferred amounts that were originally expected to be recovered in 2019. In accordance with the ECO Settlement Agreement, ECO Plan proceedings will be suspended until after the conclusion of the 2019 Base Rate Case and Mississippi Power will not be required to make any ECO Plan filings for 2018, 2019, and 2020, with any necessary true-ups to be reflected in the 2019 Base Rate Case. The ECO Settlement Agreement contains the same terms as the PEP Settlement Agreement described herein with respect to allowed ROE and equity ratio.

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Ad Valorem Tax Adjustment

On May 8, 2018, the Mississippi PSC approved Mississippi Power's annual ad valorem tax adjustment factor filing for 2018, which included an annual rate increase of 0.8%, or $7 million, in annual retail revenues effective with the first billing cycle for June 2018, primarily due to increased assessments.

Kemper County Energy Facility

For additional information on the Kemper County energy facility, see Note 3 to the financial statements of Mississippi Power under "Kemper County Energy Facility" in Item 8 of the Form 10-K.

As the mining permit holder for the Kemper County energy facility, Liberty Fuels Company, LLC has a legal obligation to perform mine reclamation, and Mississippi Power has a contractual obligation to fund all reclamation activities. Mine reclamation began in the first quarter 2018. See Note 1 to the financial statements of Mississippi Power under "Variable Interest Entities" in Item 8 of the Form 10-K for additional information.

As of June 30, 2018, Mississippi Power recorded charges to income of an immaterial amount for the second quarter 2018 and $45 million ($33 million after tax) for year-to-date 2018, primarily resulting from the abandonment and related closure activities for the mine and gasifier-related assets at the Kemper County energy facility. Additional closure costs for the mine and gasifier-related assets, currently estimated to cost up to $25 million pre-tax (excluding salvage, net of dismantlement costs), are expected to be incurred during the remainder of 2018 and 2019. In addition, period costs, including, but not limited to, costs for compliance and safety, ARO accretion, and property taxes for the mine and gasifier-related assets, are estimated at $4 million for the remainder of 2018, $7 million in 2019, and $4 million annually beginning in 2020. The ultimate outcome of this matter cannot be determined at this time.

The combined cycle and associated common facilities portions of the Kemper County energy facility were dedicated as Plant Ratcliffe on April 27, 2018.

Reserve Margin Plan

On August 6, 2018, Mississippi Power filed its proposed RMP, as required by the Mississippi PSC's order in the Kemper Settlement Docket. Under the RMP, Mississippi Power proposes alternatives that would reduce its reserve margin, with the most economic of the alternatives being the2-year and 7-year acceleration of the retirement of Plant Watson Units 4 and 5, respectively, to the first quarter 2022 and the 4-year acceleration of the retirement of Plant Greene County Units 1 and 2 to the third quarter 2021 and the third quarter 2022, respectively, in order to lower or avoid operating costs. The Plant Greene County unit retirements would require the completion by Alabama Power of proposed transmission and system reliability improvements, as well as agreement by Alabama Power. The RMP filing also states that, in the event the Mississippi PSC ultimately approves an alternative that includes an accelerated retirement, Mississippi Power would require authorization to defer in a regulatory asset for future recovery the remaining net book value of the units at the time of retirement. Mississippi Power expects the MPUS and other interested parties to review the proposal prior to resolution by the Mississippi PSC. The ultimate outcome of this matter cannot be determined at this time. However, if approved by the Mississippi PSC, the alternatives are not expected to have any adverse impact on customer rates.

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 FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk," Note (B) to the Condensed Financial Statements under "Regulatory Matters – Mississippi Power," and Note (H) to the Condensed Financial Statements herein for information regarding the Tax Reform Legislation and related regulatory actions.

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Other Matters

Mississippi Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Mississippi Power is subject to certain claims and legal actions arising in the ordinary course of business. Mississippi Power's business activities are subject to extensive governmental regulation related to public health and the environment, such as laws and regulations governing air, water, land, and protection of natural resources. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental laws and regulations 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 or regulatory matters cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements herein, 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.

On May 14, 2018, Mississippi Power's claim for lost revenue resulting from the Deepwater Horizon oil spill in the Gulf of Mexico in 2010 was settled. The settlement proceeds of $18 million, net of expenses and income tax, are included in Mississippi Power's earnings for the second quarter 2018.

To mitigate customer rate impacts associated with rising costs and declining sales, Mississippi Power management approved an employee attrition plan on July 13, 2018. Mississippi Power expects to recognize the cost of this plan, currently estimated to be between $8 million and $18 million, in the third quarter 2018.

Litigation

In 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 to include, among other things, Southern Company as a defendant. The individual plaintiff alleged that Mississippi Power and Southern Company violated the Mississippi Unfair Trade Practices Act. All plaintiffs 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 County energy facility and that these alleged breaches unjustly enriched Mississippi Power and Southern Company. The plaintiffs sought unspecified actual damages and punitive damages; asked the Circuit Court to appoint a receiver to oversee, operate, manage, and otherwise control all affairs relating to the Kemper County energy facility; asked the Circuit Court to revoke any licenses or certificates authorizing Mississippi Power or Southern Company to engage in any business related to the Kemper County energy facility in Mississippi; and sought attorney's fees, costs, and interest. The plaintiffs also sought an injunction to prevent any Kemper County energy facility costs from being charged to customers through electric rates. In June 2017, the Circuit Court ruled in favor of motions by Southern Company and Mississippi Power and dismissed the case. In July 2017, the plaintiffs filed notice of an appeal. On July 13, 2018, Mississippi Power and Southern Company reached a settlement agreement with the plaintiffs and the plaintiffs' appeal was dismissed with prejudice. The settlement had no material impact on Mississippi Power's financial statements.

On May 18, 2018, Southern Company and Mississippi Power received a notice of dispute and arbitration demand filed by Martin Product Sales, LLC (Martin) based on two agreements, both related to Kemper IGCC byproducts for which Mississippi Power provided termination notices in September 2017. Martin alleges breach of contract, breach of good faith and fair dealing, fraud and misrepresentation, and civil conspiracy and makes a claim for damages in the amount of approximately $143 million, as well as additional unspecified damages, attorney's fees, costs, and interest. Mississippi Power believes this legal challenge has no merit; however, an adverse outcome in this proceeding could have a material impact on Mississippi Power's results of operations, financial condition, and

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

liquidity. Mississippi Power will vigorously defend itself in this matter, the ultimate outcome of which cannot be determined at this time.

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.

Kemper County Energy Facility Closure Costs

As of June 30, 2018, Mississippi Power recorded charges to income of an immaterial amount for the second quarter 2018 and $45 million ($33 million after tax) for year-to-date 2018, primarily resulting from the abandonment and related closure activities for the mine and gasifier-related assets at the Kemper County energy facility. Additional closure costs for the mine and gasifier-related assets, currently estimated to cost up to $25 million pre-tax (excluding salvage, net of dismantlement costs), are expected to be incurred during the remainder of 2018 and 2019. In addition, period costs, including, but not limited to, costs for compliance and safety, ARO accretion, and property taxes for the mine and gasifier-related assets, are estimated at $4 million for the remainder of 2018, $7 million in 2019, and $4 million annually beginning in 2020. The ultimate outcome of this matter cannot be determined at this time.

See Notes 1 and 3 to the financial statements of Mississippi Power under "Variable Interest Entities" and "Kemper County Energy Facility," respectively, in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Kemper County Energy Facility" herein for additional information.

Recently Issued Accounting Standards

See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Recently Issued Accounting Standards" of Mississippi Power in Item 7 of the Form 10-K for additional information regarding ASU No. 2016-02, Leases (Topic 842). See Note (A) to the Condensed Financial Statements herein for information regarding Mississippi Power's recently adopted accounting standards.

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 for additional information.

Mississippi Power's cash requirements primarily consist of funding ongoing operations, capital expenditures, and debt maturities. Capital expenditures and other investing activities include investments to maintain existing generation facilities, to comply with environmental regulations including adding environmental modifications to certain existing generating units, to expand and improve transmission and distribution facilities, and for restoration following major storms.

In March 2018, Mississippi Power issued $300 million aggregate principal amount of Series 2018A Floating Rate Senior Notes due March 27, 2020 bearing interest based on three-month LIBOR and $300 million aggregate principal amount of Series 2018B 3.95% Senior Notes due March 30, 2028. In March 2018, Mississippi Power also entered into a $300 million short-term floating rate bank loan bearing interest based on one-month LIBOR, of which

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$200 million was repaid in the second quarter 2018 and $50 million was repaid on July 31, 2018. Mississippi Power used the proceeds from these financings to repay a $900 million unsecured term loan.

Net cash provided from operating activities totaled $297 million for the first six months of 2018, an increase of $162 million as compared to the corresponding period in 2017. The increase in cash provided from operating activities is primarily related to increased income tax refunds in 2018, partially offset by an increase in ad valorem taxes and the timing of collections of receivables. Net cash used for investing activities totaled $108 million for the first six months of 2018 primarily due to gross property additions related to steam production, distribution, and transmission. Net cash used for financing activities totaled $209 million for the first six months of 2018 primarily due to redemptions of long-term debt, partially offset by the issuance of senior notes 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 2018 include increases of $425 million in long-term debt primarily due to the issuance of senior notes and $96 million in notes payable primarily due to the issuance of a short-term bank loan. Other significant changes include a net change of $307 million in accumulated deferred income taxes due to the tax abandonment of the Kemper IGCC, as well as a decrease of $732 million in securities due within one year due to the repayment of a $900 million unsecured term loan.

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 and contractual obligations. Approximately $124 million will be required through June 30, 2019 to fund maturities of long-term debt and $100 million will be required to fund maturities of short-term debt. In addition, Mississippi Power has $40 million of tax-exempt variable rate demand obligations that are supported by short-term credit facilities and approximately $93 million of revenue bonds that were required to be remarketed over the next 12 months. Subsequent to June 30, 2018, Mississippi Power purchased and held approximately $43 million of these pollution control revenue bonds. See "Sources of Capital" herein for additional information.

Mississippi Power's purchase commitments related to LTSAs have changed to approximately $43 million for 2018, $28 million for 2019, $28 million for 2020, $29 million for 2021, $49 million for 2022, and $257 million for 2023 and thereafter due to an increase in estimated expenditures covered under the LTSA for the Kemper County energy facility.

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 laws and regulations; the outcome of any legal challenges to environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing electric generating 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. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.

Sources of Capital

Mississippi Power plans to obtain the funds required for construction and other purposes from operating cash flows, lines of credit, bank term loans, external security issuances, commercial paper (to the extent it is eligible to participate), monetization of income tax deductions associated with the abandonment of the gasifier portion of the Kemper County energy facility, and equity contributions from Southern Company. The amount, type, and timing of future financings will depend upon regulatory approval, prevailing market conditions, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" in Item 7 of the Form 10-K for additional information.

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MISSISSIPPI POWER COMPANY

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

As of June 30, 2018, Mississippi Power's current liabilities exceeded current assets by approximately $117 million as a result of $224 million of debt that matures within the next 12 months. Mississippi Power intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs.

At June 30, 2018, Mississippi Power had approximately $228 million of cash and cash equivalents. Committed credit arrangements with banks at June 30, 2018 were as follows:

Expires						Executable Term Loans		Expires Within One Year
2018		Total		Unused		One Year		Term Out		No Term Out
(in millions)
$	100	$	100	$	100	$	—	$	—	$	100

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

All of these bank credit arrangements, as well as Mississippi Power's term loan agreement, contain covenants that limit debt levels and contain cross acceleration to other indebtedness (including guarantee obligations) of Mississippi Power. 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. At June 30, 2018, Mississippi Power was in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowing.

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

A portion of the $100 million unused credit arrangements with banks is allocated to provide liquidity support to Mississippi Power's revenue bonds. The amount of variable rate revenue bonds outstanding requiring liquidity support as of June 30, 2018 was approximately $40 million. In addition, at June 30, 2018, Mississippi Power had approximately $93 million of revenue bonds outstanding that were required to be remarketed within the next 12 months.

In June 2018, Mississippi Power gave notice that approximately $43 million of its pollution control revenue bonds would be subject to mandatory tender in July 2018. Subsequent to June 30, 2018, Mississippi Power purchased and held these bonds, which may be remarketed to the public in the future.

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, 2018			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	$	100	3.3%	$	213	1.7%	$	300

(*) Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 2018.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Credit Rating Risk

At June 30, 2018, 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.

In October 2017, Mississippi Power executed agreements with its largest retail customer, Chevron, to continue providing retail service to the Chevron refinery in Pascagoula, Mississippi through 2038. The agreements grant Chevron a security interest in the co-generation assets, with a net book value of approximately $91 million, located at the refinery that is exercisable upon the occurrence of (i) certain bankruptcy events or (ii) other events of default coupled with specific reductions in steam output at the facility and a downgrade of Mississippi Power's credit rating to below investment grade by two of the three rating agencies.

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, 2018, the maximum potential collateral requirements at a rating below BBB- and/or Baa3 equaled approximately $198 million.

Included in these amounts are certain agreements that could require collateral in the event that Alabama Power or Georgia Power (affiliate companies of Mississippi Power) 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, or, at a minimum, the cost at which it does so.

On February 26, 2018, Moody's revised its rating outlook for Mississippi Power from stable to positive.

On March 14, 2018, S&P upgraded the senior unsecured long-term debt rating of Mississippi Power to A- from BBB+. The outlook remained negative.

As a result of the Tax Reform Legislation, certain financial metrics, such as the funds from operations to debt percentage, used by the credit rating agencies to assess Southern Company and its subsidiaries, including Mississippi Power, may be negatively impacted. The PEP Settlement Agreement is expected to help mitigate these potential adverse impacts by allowing Mississippi Power to retain the excess deferred taxes resulting from the Tax Reform Legislation until the conclusion of the 2019 Base Rate Case. In addition, Mississippi Power has committed to seek equity contributions sufficient to restore its equity ratio to the 50% target. See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Mississippi Power" herein for additional information.

Financing Activities

In March 2018, Mississippi Power issued $300 million aggregate principal amount of Series 2018A Floating Rate Senior Notes due March 27, 2020 bearing interest based on three-month LIBOR and $300 million aggregate principal amount of Series 2018B 3.95% Senior Notes due March 30, 2028. In March 2018, Mississippi Power also entered into a $300 million short-term floating rate bank loan bearing interest based on one-month LIBOR, of which $200 million was repaid in the second quarter 2018 and $50 million was repaid on July 31, 2018. Mississippi Power used the proceeds from these financings to repay a $900 million unsecured term loan.

Subsequent to June 30, 2018, approximately $43 million in pollution control revenue bonds of Mississippi Power were purchased and held by Mississippi Power. These bonds may be remarketed to the public in the future.

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

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SOUTHERN POWER COMPANY

AND SUBSIDIARY COMPANIES

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SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2018			2017			2018			2017
	(in millions)						(in millions)
Operating Revenues:
Wholesale revenues, non-affiliates	$	443		$	436		$	867		$	783
Wholesale revenues, affiliates	109			90			192			190
Other revenues	3			3			5			6
Total operating revenues	555			529			1,064			979
Operating Expenses:
Fuel	153			139			321			271
Purchased power	39			40			100			70
Other operations and maintenance	91			97			184			190
Depreciation and amortization	125			129			240			247
Taxes other than income taxes	12			12			24			24
Asset impairment	119			—			119			—
Total operating expenses	539			417			988			802
Operating Income	16			112			76			177
Other Income and (Expense):
Interest expense, net of amounts capitalized	(46		)	(48		)	(93		)	(97		)
Other income (expense), net	2			2			5			(2		)
Total other income and (expense)	(44		)	(46		)	(88		)	(99		)
Earnings (Loss) Before Income Taxes	(28		)	66			(12		)	78
Income taxes (benefit)	(73		)	(38		)	(172		)	(90		)
Net Income	45			104			160			168
Net income attributable to noncontrolling interests	23			22			17			17
Net Income Attributable to Southern Power	$	22		$	82		$	143		$	151

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2018			2017			2018			2017
	(in millions)						(in millions)
Net Income	$	45		$	104		$	160		$	168
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(19), $24, $(3), and $20, respectively	(55		)	40			(8		)	32
Reclassification adjustment for amounts included in net income, net of tax of $20, $(27), $12, and $(30), respectively	59			(45		)	35			(48		)
Pension and other postretirement benefit plans:
Reclassification adjustment for amounts included in net income, net of tax of $-, $-, $-, and $-, respectively	—			—			1			—
Total other comprehensive income (loss)	4			(5		)	28			(16		)
Comprehensive Income	49			99			188			152
Comprehensive income attributable to noncontrolling interests	23			22			17			17
Comprehensive Income Attributable to Southern Power	$	26		$	77		$	171		$	135

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

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Six Months Ended June 30,
	2018			2017
	(in millions)
Operating Activities:
Net income	$	160		$	168
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	256			264
Deferred income taxes	(252		)	91
Amortization of investment tax credits	(29		)	(28		)
Deferred revenues	(19		)	(34		)
Income taxes receivable, non-current	(4		)	(58		)
Asset impairment	119			—
Other, net	13			(1		)
Changes in certain current assets and liabilities —
-Receivables	(30		)	(58		)
-Prepaid income taxes	(36		)	33
-Other current assets	3			20
-Accounts payable	(41		)	(45		)
-Accrued taxes	15			4
-Other current liabilities	(28		)	(8		)
Net cash provided from operating activities	127			348
Investing Activities:
Business acquisitions	(64		)	(1,004		)
Property additions	(198		)	(145		)
Change in construction payables	2			(167		)
Payments pursuant to LTSAs	(32		)	(68		)
Other investing activities	15			(3		)
Net cash used for investing activities	(277		)	(1,387		)
Financing Activities:
Increase (decrease) in notes payable, net	(41		)	189
Proceeds —
Short-term borrowings	200			—
Capital contributions from parent company	16			—
Redemptions —
Return of paid in capital	(250		)	—
Senior notes	(350		)	—
Other long-term debt	(420		)	(3		)
Distributions to noncontrolling interests	(42		)	(40		)
Capital contributions from noncontrolling interests	1,210			73
Payment of common stock dividends	(156		)	(158		)
Other financing activities	(15		)	(18		)
Net cash provided from financing activities	152			43
Net Change in Cash, Cash Equivalents, and Restricted Cash	2			(996		)
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	140			1,112
Cash, Cash Equivalents, and Restricted Cash at End of Period	$	142		$	116
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $10 and $4 capitalized for 2018 and 2017, respectively)	$	109		$	113
Income taxes, net	109			(117		)
Noncash transactions — Accrued property additions at end of period	33			19

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

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CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

Assets	At June 30, 2018		At December 31, 2017
	(in millions)
Current Assets:
Cash and cash equivalents	$	142	$	129
Receivables —
Customer accounts receivable	165		117
Affiliated	60		50
Other	63		98
Materials and supplies	213		278
Prepaid income taxes	82		50
Assets held for sale, current	17		1
Other current assets	31		35
Total current assets	773		758
Property, Plant, and Equipment:
In service	13,402		13,755
Less: Accumulated provision for depreciation	1,959		1,910
Plant in service, net of depreciation	11,443		11,845
Construction work in progress	771		511
Total property, plant, and equipment	12,214		12,356
Other Property and Investments:
Intangible assets, net of amortization of $60 and $47 at June 30, 2018 and December 31, 2017, respectively	398		411
Total other property and investments	398		411
Deferred Charges and Other Assets:
Prepaid LTSAs	93		118
Accumulated deferred income taxes	1,223		925
Income taxes receivable, non-current	81		72
Assets held for sale	183		—
Other deferred charges and assets	463		566
Total deferred charges and other assets	2,043		1,681
Total Assets	$	15,428	$	15,206

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

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CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholders' Equity	At June 30, 2018		At December 31, 2017
	(in millions)
Current Liabilities:
Securities due within one year	$	—	$	770
Notes payable	264		105
Accounts payable —
Affiliated	75		102
Other	84		103
Liabilities held for sale, current	2		—
Other current liabilities	146		152
Total current liabilities	571		1,232
Long-term Debt	5,037		5,071
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	135		199
Accumulated deferred ITCs	1,856		1,884
Other deferred credits and liabilities	255		322
Total deferred credits and other liabilities	2,246		2,405
Total Liabilities	7,854		8,708
Common Stockholder's Equity:
Common stock, par value $0.01 per share —
Authorized — 1,000,000 shares
Outstanding — 1,000 shares	—		—
Paid-in capital	3,023		3,662
Retained earnings	1,464		1,478
Accumulated other comprehensive income (loss)	31		(2		)
Total common stockholder's equity	4,518		5,138
Noncontrolling interests	3,056		1,360
Total stockholders' equity	7,574		6,498
Total Liabilities and Stockholders' Equity	$	15,428	$	15,206

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

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

SECOND QUARTER 2018 vs. SECOND QUARTER 2017

AND

YEAR-TO-DATE 2018 vs. YEAR-TO-DATE 2017

OVERVIEW

Southern Power develops, constructs, acquires, owns, and manages power 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, development and construction of new generating facilities, and entry into PPAs primarily with investor-owned utilities, independent power producers, municipalities, electric cooperatives, and other load-serving entities, as well as commercial and industrial customers. In general, Southern Power has committed to the construction or acquisition of new generating capacity only after entering into or assuming long-term PPAs for the new facilities.

In May 2018, Southern Power completed the sale of a 33% equity interest in SPSH, a newly-formed limited partnership indirectly owning substantially all of Southern Power's solar facilities, for an aggregate purchase price of approximately $1.2 billion, subject to customary working capital adjustments. Southern Power maintains control and overall operational responsibilities for the solar facilities.

Also in May 2018, Southern Power entered into an agreement to sell all of its equity interests in two natural gas-fired operating facilities, Plant Oleander and Plant Stanton Unit A (together, the Florida Plants), for an aggregate purchase price of $195 million, subject to customary working capital and timing adjustments. The sale is subject to certain closing and timing conditions and approvals and is expected to occur in the first half of 2019. As a result of this pending transaction, Southern Power recorded an asset impairment charge of approximately $119 million ($89 million after tax) in the second quarter 2018. See Note (J) to the Condensed Financial Statements under "Southern Power" herein for additional information. The ultimate outcome of this matter cannot be determined at this time.

Southern Power is pursuing the sale of a noncontrolling interest in a portfolio of eight operating wind facilities through the use of third-party tax equity, which, if successful, is expected to close in the fourth quarter 2018. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Legal Entity Reorganizations" herein for additional information. The ultimate outcome of this matter cannot be determined at this time.

During the six months ended June 30, 2018, Southern Power acquired and placed in-service the 20-MW Gaskell West 1 solar facility, acquired and began construction of the 100-MW Wild Horse Mountain wind facility, and continued construction of the 148-MW Cactus Flats wind facility and the expansion of the 345-MW Mankato natural gas facility. See FUTURE EARNINGS POTENTIAL – "Acquisitions" and "Construction Projects" herein for additional information.

At June 30, 2018, Southern Power's average investment coverage ratio for its generating assets (including the Florida Plants), based on 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 and acquisitions discussed herein) as the investment amount, was 92% through 2022 and 90% through 2027, with an average remaining contract duration of approximately 15 years. See FUTURE EARNINGS POTENTIAL – "Power Sales Agreements" herein for additional information.

See FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein for information regarding Southern Power's revised capital expenditure forecasts for 2018 through 2022.

Southern Power continues to focus on several key performance indicators, including, but not limited to, peak season equivalent forced outage rate, contract availability, and net income.

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RESULTS OF OPERATIONS

Net Income Attributable to Southern Power

Second Quarter 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$(60)	(73.2)	$(8)	(5.3)

Net income attributable to Southern Power for the second quarter 2018 was $22 million compared to $82 million for the corresponding period in 2017. Net income attributable to Southern Power for year-to-date 2018 was $143 million compared to $151 million for the corresponding period in 2017. The decreases were primarily due to a $119 million asset impairment charge ($89 million after tax) as a result of the pending sale of the Florida Plants. The year-to-date decrease was partially offset by approximately $54 million in state income tax benefits arising from the reorganization of Southern Power's legal entities that own and operate its solar facilities.

Operating Revenues

Second Quarter 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$26	4.9	$85	8.7

Total 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 from Southern Power's generation facilities. To the extent Southern Power has capacity not contracted under a PPA, it may sell power into the wholesale market and, to the extent the generation assets are part of the IIC, as approved by the FERC, it may sell power into the power pool.

Natural Gas and Biomass Capacity and Energy Revenue

Capacity revenues generally represent the greatest contribution to net income and are designed to provide recovery of fixed costs plus a return on investment.

Energy is generally sold at variable cost or is indexed to published natural gas indices. Energy 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. Energy revenues also include fees for support services, fuel storage, and unit start charges. Increases and decreases in energy revenues under PPAs that are driven by fuel or purchased power prices are accompanied by an increase or decrease in fuel and purchased power costs and do not have a significant impact on net income.

Solar and Wind Energy Revenue

Southern Power's energy sales from solar and wind generating facilities are predominantly through long-term PPAs that do not have a capacity charge. Customers either purchase the energy output of a dedicated renewable facility through an energy charge or pay a fixed price related to the energy sold to the grid. 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, transmission constraints, and other factors.

See FUTURE EARNINGS POTENTIAL – "Power Sales Agreements" herein for additional information regarding Southern Power's PPAs.

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Details of Southern Power's operating revenues were as follows:

	Second Quarter 2018		Second Quarter 2017		Year-to-Date 2018		Year-to-Date 2017
	(in millions)
PPA capacity revenues	$	144	$	149	$	282	$	298
PPA energy revenues	302		270		556		466
Total PPA revenues	446		419		838		764
Non-PPA revenues	106		107		221		209
Other revenues	3		3		5		6
Total operating revenues	$	555	$	529	$	1,064	$	979

In the second quarter 2018, total operating revenues were $555 million, reflecting a $26 million, or 5%, increase from the corresponding period in 2017. The increase in operating revenues was primarily due to the following:

• PPA capacity revenues decreased $5 million, or 3%, primarily due to the contractual expiration of an affiliate natural gas PPA.

• PPA energy revenues increased $32 million, or 12%, primarily due to an $18 million increase from new natural gas PPAs from existing facilities and a $10 million increase from renewable facilities primarily due to an increase in the volume of KWHs sold, including new solar facilities in service.

For year-to-date 2018, total operating revenues were $1.1 billion, reflecting an $85 million, or 9%, increase from the corresponding period in 2017. The increase in operating revenues was primarily due to the following:

• PPA capacity revenues decreased $16 million, or 5%, primarily due to the contractual expiration of an affiliate natural gas PPA.

• PPA energy revenues increased $90 million, or 19%, primarily due to $37 million in increased fuel costs that are contractually recovered through existing PPAs, a $36 million increase from new natural gas PPAs from existing facilities, and an $18 million increase from renewable facilities primarily due to an increase in the volume of KWHs sold, including new solar facilities in service.

• Non-PPA revenues increased $12 million, or 6%, primarily due to an increase in the volume of KWHs sold from uncovered natural gas capacity through short-term sales.

Fuel and Purchased Power Expenses

Fuel costs constitute one of the largest expenses for Southern Power. In addition, Southern Power purchases a portion of its electricity needs from the wholesale market including the power pool. Details of Southern Power's generation and purchased power were as follows:

	Second Quarter 2018	Second Quarter 2017	Year-to-Date 2018	Year-to-Date 2017
	(in billions of KWHs)
Generation	12.2	10.9	22.0	20.6
Purchased power	1.2	1.2	2.2	2.2
Total generation and purchased power	13.4	12.1	24.2	22.8
Total generation and purchased power, excluding solar, wind, and tolling agreements	7.2	5.6	13.9	10.5

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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, changes in such fuel costs are generally accompanied by a corresponding change in related fuel revenues and do 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.

Purchased power expenses will vary depending on demand, availability, and the 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, an affiliate company, or external parties. Such purchased power costs are generally recovered through PPA revenues.

Details of Southern Power's fuel and purchased power expenses were as follows:

	Second Quarter 2018 vs. Second Quarter 2017				Year-to-Date 2018 vs. Year-to-Date 2017
	(change in millions)			(% change)	(change in millions)		(% change)
Fuel	$	14		10.1	$	50	18.5
Purchased power	(1		)	(2.5)	30		42.9
Total fuel and purchased power expenses	$	13			$	80

In the second quarter 2018, total fuel and purchased power expenses increased $13 million, or 7%, compared to the corresponding period in 2017. Fuel expense increased $14 million primarily due to a $48 million increase in the volume of KWHs generated, excluding solar, wind, and tolling agreements, partially offset by a $37 million decrease in the average cost of natural gas per KWH generated.

For year-to-date 2018, total fuel and purchased power expenses increased $80 million, or 23%, compared to the corresponding period in 2017. Fuel expense increased $50 million primarily due to a $108 million increase in the volume of KWHs generated, excluding solar, wind, and tolling agreements, partially offset by a $59 million decrease in the average cost of natural gas per KWH generated. Purchased power expense increased $30 million primarily due to an increase in the average cost of purchased power in first quarter 2018.

Asset Impairment

In the second quarter 2018, a $119 million asset impairment charge was recorded as a result of the pending sale of the Florida Plants, expected to occur in the first half 2019.

See Note (J) under "Southern Power – Sale of Florida Plants" to the Condensed Financial Statements herein for additional information.

Income Taxes (Benefit)

Second Quarter 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$(35)	(92.1)	$(82)	(91.1)

In the second quarter 2018, income tax benefit was $73 million compared to $38 million for the corresponding period in 2017. For year-to-date 2018, income tax benefit was $172 million compared to $90 million for the corresponding period in 2017. The increases were primarily due to lower pre-tax earnings, primarily resulting from the asset impairment charge, and income tax benefits arising from a reorganization of Southern Power's legal entities that own and operate substantially all of its solar facilities related to certain changes in state apportionment

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

rates. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Legal Entity Reorganizations" and Note (H) 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 strategy, including successful additional investments in renewable and other energy projects, and to develop and construct generating facilities.

In May 2018, Southern Power completed the sale of a 33% equity interest in SPSH, a newly-formed limited partnership indirectly owning substantially all of Southern Power's solar facilities, to Global Atlantic Financial Group Limited (Global Atlantic) for approximately $1.2 billion, subject to customary working capital adjustments. Accordingly, Global Atlantic will receive 33% of all cash distributions paid by SPSH. Southern Power continues to consolidate the assets and liabilities of SPSH with Global Atlantic's share of partnership earnings reflected in net income attributable to noncontrolling interests in the Condensed Consolidated Statements of Income.

Also in May 2018, Southern Power entered into an equity interest purchase agreement with NextEra Energy to sell all of its equity interests in the Florida Plants for an aggregate purchase price of $195 million, subject to customary working capital and timing adjustments. The ultimate purchase price will decrease $110,000 per day for each day after December 31, 2018 through the closing of the transaction. Conversely, the ultimate purchase price will increase $110,000 per day for each day the closing occurs prior to December 31, 2018. The sale is expected to occur in the first half of 2019. Excluding any interest allocation for corporate debt, the pre-tax net income for the Florida Plants was $14 million and $11 million for the three months ended June 30, 2018 and 2017, respectively, and $24 million and $20 million for the six months ended June 30, 2018 and 2017, respectively. The ultimate outcome of this matter cannot be determined at this time.

Southern Power is pursuing the sale of a noncontrolling interest in a portfolio of eight operating wind facilities through the use of third-party tax equity, which, if successful, is expected to close in the fourth quarter 2018. See "Income Tax Matters – Legal Entity Reorganizations" herein for additional information. The ultimate outcome of this matter cannot be determined at this time. If the transaction is completed, the tax equity partner, or partners, will have a claim to certain cash distributions and an allocation of tax attributes.

Demand for electricity is primarily driven by the pace of economic growth that may be affected by changes in regional and global economic conditions, as well as renewable portfolio standards, which may impact future earnings. Other factors that could influence future earnings include weather, transmission constraints, cost of generation from units within the power pool, and operational limitations. For additional information relating to these factors, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Southern Power in Item 7 of the Form 10-K.

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 June 30, 2018, Southern Power's average investment coverage ratio for its generating assets (including the Florida Plants), based on 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 and acquisitions discussed herein) as the investment amount, was 92% through 2022 and 90% through 2027, with an average remaining contract duration of approximately 15 years.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 legislative or regulatory changes cannot be determined at this time.

Water Quality

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Water Quality" of Southern Power in Item 7 of the Form 10-K for additional information regarding the effluent limitations guidelines (ELG) rule.

On May 2, 2018, the EPA updated its anticipated final rulemaking schedule for ELG from September 2020 to December 2019. The impact of any changes to the ELG rule will depend on the content of the final rule and the outcome of any legal challenges and cannot be determined at this time.

FERC Matters

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters" of Southern Power in Item 7 of the Form 10-K for additional information regarding proceedings related to the traditional electric operating companies'and Southern Power's 2014 and 2017 triennial market power analyses.

On May 4, 2018, the FERC issued an order terminating both proceedings, finding that the traditional electric operating companiesand Southern Power satisfy the FERC's standards for market-based rates. On May 9, 2018, the traditional electric operating companiesand Southern Power made the compliance filing required by the order. These proceedings are essentially concluded.

Acquisitions

During the six months ended June 30, 2018, one of Southern Power's wholly-owned subsidiaries acquired and completed construction of the Gaskell West 1 solar facility. Acquisition-related costs were expensed as incurred and were not material. See Note (J) to the Condensed Financial Statements under "Southern Power" herein and 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 additional information.

Project Facility	Resource	Approximate Nameplate Capacity (MW)	Location	Percentage Ownership		Actual COD	PPA Counterparties	PPA Contract Period
Gaskell West 1	Solar	20	Kern County, CA	100% of Class B	(*)	March 2018	Southern California Edison	20 years

(*) Southern Power owns 100% of the class B membership interests under a tax equity partnership agreement.

The Gaskell West 1 facility did not have operating revenues or activities prior to completion of construction and the assets being placed in service during March 2018.

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

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Construction Projects Completed and in Progress

During the six months ended June 30, 2018, Southern Power started or continued construction of the projects set forth in the table below. Total aggregate construction costs, excluding the acquisition costs, are expected to be between $520 million and $590 million for the Cactus Flats, Mankato, and Wild Horse Mountain facilities. At June 30, 2018, construction costs included in CWIP related to these projects totaled $353 million. The ultimate outcome of these matters cannot be determined at this time.

Project Facility	Resource	Approximate Nameplate Capacity (MW)	Location	Actual/Expected COD	PPA Counterparties	PPA Contract Period
Projects Under Construction as of June 30, 2018
Cactus Flats(a)	Wind	148	Concho County, TX	July 2018	General Motors, LLC and General Mills Operations, LLC	12 years and 15 years
Mankato	Natural Gas	345	Mankato, MN	First half 2019	Northern States Power Company	20 years
Wild Horse Mountain(b)	Wind	100	Pushmataha County, OK	Fourth quarter 2019	Arkansas Electric Cooperative	20 years

(a) In July 2017, Southern Power purchased 100% of the Cactus Flats facility and commenced construction. Subsequent to June 30, 2018, the facility was placed in service and Southern Power expects to close on a tax equity partnership agreement, which would result in Southern Power owning 100% of the class B membership interests.

(b) In May 2018, Southern Power purchased 100% of the Wild Horse Mountain facility and commenced construction. Southern Power may enter into a tax equity partnership agreement, in which case it would then own 100% of the class B membership interests.

Development Projects

During 2017, as part of its renewable development strategy, Southern Power purchased wind turbine equipment from Siemens Gamesa Renewable Energy Inc. and Vestas-American Wind Technology, Inc. to be used for various development and construction projects. Any wind projects reaching commercial operation by 2021 are expected to qualify for 80% PTCs.

During 2016, Southern Power entered into a joint development agreement with Renewable Energy Systems Americas, Inc. to develop and construct wind projects. In addition, in 2016, Southern Power purchased wind turbine equipment from Siemens Wind Power, Inc. and Vestas-American Wind Technology, Inc. to be used for construction of the facilities. Any wind projects reaching commercial operation by 2020 are expected to qualify for 100% PTCs.

In response to the previously disclosed decrease of planned expenditures for plant acquisitions and placeholder growth, Southern Power continues to refine the deployment of wind turbine equipment to projects and the amount of MW capacity to be constructed. While the expectation is that the majority of the equipment will be deployed in a manner to qualify for the 100% and 80% PTCs, Southern Power may consider other strategies, such as selling equipment or interests in projects. See FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein.

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

Income Tax Matters

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters" of Southern Power in Item 7 of the Form 10-K and FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" and Note (H) to the Condensed Financial Statements herein for information regarding the Tax Reform Legislation.

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Legal Entity Reorganizations

In March 2018, Southern Power substantially completed a legal entity reorganization of various direct and indirect subsidiaries that own and operate substantially all of its solar facilities, including certain subsidiaries owned in partnership with various third parties. The reorganization resulted in net state tax benefits related to certain changes in apportionment rates totaling approximately $50 million, which were recorded in the first quarter 2018. In April 2018, Southern Power completed the final stage of the reorganization resulting in additional net state tax benefits of approximately $4 million.

Southern Power is pursuing the sale of a noncontrolling interest in a portfolio of eight operating wind facilities through the use of third-party tax equity, which, if successful, is expected to close in the fourth quarter 2018. In the third quarter 2018, various direct and indirect subsidiaries of Southern Power that own and operate these wind facilities are expected to be reorganized under a new holding company in which the tax equity partner would invest. The reorganization is expected to result in estimated net state tax benefits totaling approximately $10 million related to certain changes in apportionment rates. The ultimate outcome of this matter cannot be determined at this time.

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 laws and regulations governing air, water, land, and protection of natural resources. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental laws and regulations has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO₂ and other emissions and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.

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

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

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

Recently Issued Accounting Standards

See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Recently Issued Accounting Standards" of Southern Power in Item 7 of the Form 10-K for additional information regarding ASU No. 2016-02, Leases (Topic 842). See Note (A) to the Condensed Financial Statements herein for information regarding Southern Power's recently adopted accounting standards.

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FINANCIAL CONDITION AND LIQUIDITY

Overview

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Southern Power in Item 7 of the Form 10-K for additional information. Southern Power's financial condition remained stable at June 30, 2018. 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.

Southern Power also utilizes third-party tax equity partnerships as one of the financing sources to fund its renewable growth strategy where the tax partner takes significantly all of the federal tax benefits. These tax equity partnerships are consolidated in Southern Power's financial statements using a hypothetical liquidation at book value (HLBV) methodology to allocate partnership gains and losses to Southern Power. In the first half of 2018, Southern Power secured third-party tax equity funding for the Gaskell West 1 solar project of approximately $26 million and expects to obtain tax equity funding for the Cactus Flats wind project in the third quarter 2018. See Note (A) to the Condensed Financial Statements under "Hypothetical Liquidation at Book Value" herein for additional information on the HLBV methodology.

In May 2018, Southern Power received approximately $1.2 billion from the sale of a 33% equity interest in SPSH, a newly-formed limited partnership indirectly owning substantially all of Southern Power's solar facilities. The proceeds were used to repay $770 million of existing indebtedness, to return capital of $250 million to Southern Company, and for other general corporate purposes, including working capital.

Southern Power is pursuing the sale of a noncontrolling interest in a portfolio of eight operating wind facilities through the use of third-party tax equity, which, if successful, is expected to close in the fourth quarter 2018. The ultimate outcome of this matter cannot be determined at this time.

Net cash provided from operating activities totaled $127 million for the first six months of 2018 compared to $348 million for the first six months of 2017. The decrease in net cash provided from operating activities was primarily due to income tax payments. See FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Bonus Depreciation" of Southern Power in Item 7 of the Form 10-K for additional information. Net cash used for investing activities totaled $277 million for the first six months of 2018 primarily due to the construction of generating facilities and payments for renewable acquisitions. Net cash provided from financing activities totaled $152 million for the first six months of 2018 primarily due to proceeds from the sale of a 33% equity interest in SPSH, primarily offset by debt repayments and equity distributions. Cash flows from financing activities may 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 2018 include a $1.7 billion increase in noncontrolling interests, a $639 million reduction in paid in capital, and a $298 million increase in accumulated deferred income tax assets primarily due to the sale of a 33% equity interest in SPSH and a $770 million decrease in securities due within one year due to repayments in May and June 2018.

See FUTURE EARNINGS POTENTIAL – "Acquisitions," "Construction Projects," and "Income Tax Matters – Legal Entity Reorganizations" 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 and contractual obligations. There are no scheduled maturities of long-term debt through June 30, 2019.

Southern Power's construction program includes estimates for potential plant acquisitions and placeholder growth, new construction and development, capital improvements, and work to be performed under LTSAs and is subject to periodic review and revision. Subsequent to the Tax Reform Legislation, planned expenditures for plant acquisitions

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

and placeholder growth are now expected to average approximately $0.5 billion per year for 2018 through 2022 and may vary materially due to market opportunities and Southern Power's ability to execute its growth strategy. Southern Power's capital expenditures for committed construction, capital improvements, and work to be performed under LTSAs remain unchanged and total approximately $0.9 billion for the five years ending 2022. Actual construction 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 laws and regulations; the outcome of any legal challenges to 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 FUTURE EARNINGS POTENTIAL – "Acquisitions" and "Construction Projects" herein for additional information.

Sources of Capital

Southern Power plans to obtain the funds required for acquisitions, construction, development, debt maturities, and other purposes from operating cash flows, external securities issuances, borrowings from financial institutions, tax equity partnership contributions, divestitures, 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.

Southern Power's current liabilities sometimes exceed current assets due to the use of short-term debt as a funding source and construction payables, as well as fluctuations in cash needs, due to seasonality. Southern Power believes the need for working capital can be adequately met by utilizing the commercial paper program, the Facility (as defined below), bank term loans, the debt capital markets, and operating cash flows.

As of June 30, 2018, Southern Power had cash and cash equivalents of approximately $142 million.

Southern Power's commercial paper program is used to finance acquisition and construction costs related to electric generating facilities, for general corporate purposes, and to finance maturing debt. Commercial paper is included in notes payable on the condensed consolidated balance sheets.

Details of short-term borrowings were as follows:

	Short-term Debt at June 30, 2018				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	$	64	2.4	%	$	171	2.3	%	$	304
Short-term loans	200		2.7	%	76		2.6	%	200
Total	$	264	2.6	%	$	247	2.4	%

(*) Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 2018.

At June 30, 2018, Southern Power had a committed credit facility (Facility) of $750 million, of which $22 million has been used for letters of credit and $728 million remains unused. The Facility expires in 2022. 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 (F) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.

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

Southern Power also has a $120 million continuing letter of credit facility expiring in 2019 for standby letters of credit. At June 30, 2018, $97 million has been used for letters of credit, primarily as credit support for PPA requirements, and $23 million remains unused.

In addition, at June 30, 2018, Southern Power had $106 million of cash collateral posted related to PPA requirements.

Southern Power's subsidiaries do not borrow under the commercial paper program and are not parties to, and do not borrow under, the Facility or the continuing letter of credit facility.

Credit Rating Risk

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

There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB and/or Baa2, or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, energy price risk management, and transmission.

The maximum potential collateral requirements under these contracts at June 30, 2018 were as follows:

Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB and/or Baa2	$	37
At BBB- and/or Baa3	$	377
At BB+ and/or Ba1(*)	$	955

(*) Any additional credit rating downgrades at or below BB- and/or Ba3 could increase collateral requirements up to an additional $38 million.

Included in these amounts are certain agreements that could require collateral in the event that Alabama Power or Georgia Power (affiliate companies of Southern Power) 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 resulting from a credit downgrade.

As a result of the Tax Reform Legislation, certain financial metrics, such as the funds from operations to debt percentage, used by the credit rating agencies to assess Southern Company and its subsidiaries, including Southern Power, may be negatively impacted. Absent actions by Southern Power to mitigate the resulting impacts, which, among other alternatives, could include adjusting Southern Power's capital structure, Southern Power's credit ratings could be negatively affected.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Financing Activities

In May 2018, Southern Power entered into two short-term floating rate bank loans, each for an aggregate principal amount of $100 million, which bear interest based on one-month LIBOR.

In the second quarter 2018, Southern Power used a portion of the proceeds from the sale of a 33% equity interest in SPSH to repay $420 million aggregate principal amount of long-term floating rate bank loans and $350 million aggregate principal amount of Series 2015A 1.50% Senior Notes due June 1, 2018. See Note (J) to the Condensed Financial Statements under "Southern Power – Sale of Solar Facility Interests" herein for additional information.

Southern Power received approximately $26 million of third-party tax equity during the six months ended June 30, 2018 related to the Gaskell West 1 solar facility.

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.

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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,
	2018			2017			2018			2017
	(in millions)						(in millions)
Operating Revenues:
Natural gas revenues (includes revenue taxes of $23, $19, $74, and $67, respectively)	$	710		$	684		$	2,341		$	2,205
Alternative revenue programs	(4		)	—			(27		)	9
Other revenues	24			32			55			62
Total operating revenues	730			716			2,369			2,276
Operating Expenses:
Cost of natural gas	228			232			949			951
Cost of other sales	5			6			12			13
Other operations and maintenance	238			214			514			470
Depreciation and amortization	126			125			255			244
Taxes other than income taxes	48			44			125			114
Goodwill impairment	—			—			42			—
Loss on disposition	36			—			36			—
Total operating expenses	681			621			1,933			1,792
Operating Income	49			95			436			484
Other Income and (Expense):
Earnings from equity method investments	31			29			74			68
Interest expense, net of amounts capitalized	(59		)	(48		)	(118		)	(94		)
Other income (expense), net	3			4			15			10
Total other income and (expense)	(25		)	(15		)	(29		)	(16		)
Earnings Before Income Taxes	24			80			407			468
Income taxes	55			31			159			180
Net Income (Loss)	$	(31	)	$	49		$	248		$	288

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2018			2017			2018		2017
	(in millions)						(in millions)
Net Income (Loss)	$	(31	)	$	49		$	248	$	288
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $-, $(1), $-, and $(2), respectively	1			(1		)	1		(2		)
Reclassification adjustment for amounts included in net income, net of tax of $-, $-, $1, and $-, respectively	—			—			2		—
Pension and other postretirement benefit plans:
Reclassification adjustment for amounts included in net income, net of tax of $-, $-, $-, and $-, respectively	—			—			—		(1		)
Total other comprehensive income (loss)	1			(1		)	3		(3		)
Comprehensive Income (Loss)	$	(30	)	$	48		$	251	$	285

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

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Six Months Ended June 30,
	2018			2017
	(in millions)
Operating Activities:
Net income	$	248		$	288
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	255			244
Deferred income taxes	(12		)	144
Mark-to-market adjustments	2			(49		)
Goodwill impairment	42			—
Loss on disposition	36			—
Other, net	(24		)	(34		)
Changes in certain current assets and liabilities —
-Receivables	504			418
-Natural gas for sale, net of temporary LIFO liquidation	295			223
-Prepaid income taxes	9			24
-Other current assets	32			(12		)
-Accounts payable	(125		)	(102		)
-Accrued taxes	38			(8		)
-Accrued compensation	(6		)	(12		)
-Other current liabilities	24			25
Net cash provided from operating activities	1,318			1,149
Investing Activities:
Property additions	(679		)	(684		)
Cost of removal, net of salvage	(18		)	(25		)
Change in construction payables, net	(6		)	23
Investment in unconsolidated subsidiaries	(60		)	(111		)
Disposition	364			—
Other investing activities	18			18
Net cash used for investing activities	(381		)	(779		)
Financing Activities:
Decrease in notes payable, net	(515		)	(631		)
Proceeds —
Capital contributions from parent company	10			57
Senior notes	—			450
Redemptions — Gas facility revenue bonds	(200		)	—
Payment of common stock dividends	(235		)	(221		)
Other financing activities	—			(6		)
Net cash used for financing activities	(940		)	(351		)
Net Change in Cash, Cash Equivalents, and Restricted Cash	(3		)	19
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	78			24
Cash, Cash Equivalents, and Restricted Cash at End of Period	$	75		$	43
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $3 and $7 capitalized for 2018 and 2017, respectively)	$	129		$	105
Income taxes, net	106			20
Noncash transactions — Accrued property additions at end of period	129			84

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

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CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

Assets	At June 30, 2018			At December 31, 2017
	(in millions)
Current Assets:
Cash and cash equivalents	$	69		$	73
Receivables —
Energy marketing receivables	451			607
Customer accounts receivable	243			400
Unbilled revenues	60			285
Other accounts and notes receivable	53			103
Accumulated provision for uncollectible accounts	(26		)	(28		)
Natural gas for sale	292			595
Prepaid expenses	64			53
Assets from risk management activities, net of collateral	93			135
Other regulatory assets, current	55			94
Assets held for sale, current	2,298			—
Other current assets	42			78
Total current assets	3,694			2,395
Property, Plant, and Equipment:
In service	14,504			15,833
Less: Accumulated depreciation	4,293			4,596
Plant in service, net of depreciation	10,211			11,237
Construction work in progress	571			491
Total property, plant, and equipment	10,782			11,728
Other Property and Investments:
Goodwill	5,015			5,967
Equity investments in unconsolidated subsidiaries	1,507			1,477
Other intangible assets, net of amortization of $121 and $120 at June 30, 2018 and December 31, 2017, respectively	125			280
Miscellaneous property and investments	20			21
Total other property and investments	6,667			7,745
Deferred Charges and Other Assets:
Other regulatory assets, deferred	742			901
Other deferred charges and assets	227			218
Total deferred charges and other assets	969			1,119
Total Assets	$	22,112		$	22,987

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

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CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

Liabilities and Stockholder's Equity	At June 30, 2018			At December 31, 2017
	(in millions)
Current Liabilities:
Securities due within one year	$	156		$	157
Notes payable	1,003			1,518
Energy marketing trade payables	485			546
Accounts payable	359			446
Customer deposits	101			128
Accrued taxes —
Accrued income taxes	86			40
Other accrued taxes	63			78
Accrued interest	53			51
Accrued compensation	61			74
Liabilities from risk management activities, net of collateral	21			69
Other regulatory liabilities, current	162			135
Liabilities held for sale, current	412			—
Other current liabilities	143			159
Total current liabilities	3,105			3,401
Long-term Debt	5,667			5,891
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	1,026			1,089
Deferred credits related to income taxes	920			1,063
Employee benefit obligations	389			415
Other cost of removal obligations	1,575			1,646
Accrued environmental remediation, deferred	273			342
Other deferred credits and liabilities	96			118
Total deferred credits and other liabilities	4,279			4,673
Total Liabilities	13,051			13,965
Common Stockholder's Equity:
Common stock, par value $0.01 per share —
Authorized — 100 million shares
Outstanding — 100 shares	—			—
Paid in capital	9,236			9,214
Accumulated deficit	(202		)	(212		)
Accumulated other comprehensive income	27			20
Total common stockholder's equity	9,061			9,022
Total Liabilities and Stockholder's Equity	$	22,112		$	22,987

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

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

SECOND QUARTER 2018 vs. SECOND QUARTER 2017

AND

YEAR-TO-DATE 2018 vs. YEAR-TO-DATE 2017

OVERVIEW

Southern Company Gas is an energy services holding company whose primary business is the distribution of natural gas. Subsequent to the dispositions of Elizabethtown Gas, Elkton Gas, and Florida City Gas discussed below, Southern Company Gas has natural gas distribution utilities in four states – Illinois, Georgia, Virginia, and Tennessee. Southern Company Gas and its subsidiaries are also involved in several other complementary businesses.

Southern Company Gas has four reportable segments – gas distribution operations, gas marketing services, wholesale gas services, and gas midstream operations – and one non-reportable segment – all other. For additional information on these segments, see Note (L) to the Condensed Financial Statements herein and "BUSINESS – The Southern Company System – Southern Company Gas" in Item 1 of the Form 10-K.

Many factors affect the opportunities, challenges, and risks of Southern Company Gas' business. These factors include the ability to maintain safety, to maintain constructive regulatory environments, to maintain and grow natural gas sales and number of customers, and to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand growth, environmental standards, reliability, natural gas, and capital expenditures, including updating and expanding the natural gas distribution systems. The natural gas distribution utilities have various regulatory mechanisms that 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 Southern Company Gas for the foreseeable future.

On June 4, 2018, Southern Company Gas completed the stock sale of Pivotal Home Solutions to American Water Enterprises LLC for a total cash purchase price of $358 million and an additional $6 million for working capital. This disposition resulted in a net loss of $76 million, which included $40 million of income tax expense. In contemplation of the transaction, a goodwill impairment charge of $42 million was recorded during the first quarter 2018.

On July 1, 2018, a Southern Company Gas subsidiary, Pivotal Utility Holdings, completed the sales of the assets of two of its natural gas distribution utilities, Elizabethtown Gas and Elkton Gas, to South Jersey Industries, Inc. for a total cash purchase price of $1.7 billion and an additional $40 million for working capital. This disposition resulted in an estimated pre-tax gain of approximately $235 million and an after-tax gain of approximately $12 million, which will be recorded in the third quarter 2018.

On July 29, 2018, Southern Company Gas and its wholly-owned direct subsidiary, NUI Corporation, completed the stock sale of Pivotal Utility Holdings, which primarily consisted of Florida City Gas, to NextEra Energyfor a total cash purchase price of $530 million (less $3 million of indebtedness assumed at closing for customer deposits) and an additional $60 million for cash and other working capital. This disposition resulted in an estimated pre-tax gain of approximately $126 million and an after-tax gain of approximately $4 million, which will be recorded in the third quarter 2018.

The after-tax impacts of these dispositions included income tax expense on goodwill not deductible for tax purposes and for which a deferred tax liability had not been recorded previously. Additionally, each of these dispositions is subject to a final working capital adjustment that may impact the cash proceeds from disposition, but not the gain recorded. See Note (J) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information on these dispositions.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Operating Metrics

Southern Company Gas continues to focus on several operating metrics, including Heating Degree Days, customer count, and volumes of natural gas sold. For additional information on these indicators, see MANAGEMENT'S DISCUSSION AND ANALYSIS – OVERVIEW – "Operating Metrics" of Southern Company Gas in Item 7 of the Form 10-K.

Southern Company Gas measures weather and the effect on its business using Heating Degree Days. Generally, increased Heating Degree Days result in higher demand for natural gas on Southern Company Gas' distribution system. With the exception of Nicor Gas, Southern Company Gas has various regulatory mechanisms, such as weather normalization and straight-fixed-variable rate design, which limit its exposure to weather changes within typical ranges in each of its utilities' respective service territory. However, the utility customers in Illinois and the gas marketing services customers primarily in Georgia and Illinois can be impacted by warmer- or colder-than-normal weather. Southern Company Gas utilizes weather hedges to reduce negative earnings impact in the event of warmer-than-normal weather, while retaining most of the earnings upside for these businesses.

The number of customers served by gas distribution operations and gas marketing services can be impacted by natural gas prices, economic conditions, and competition from alternative fuels. Gas marketing services' customers are primarily located in Georgia, Illinois, and Ohio.

Southern Company Gas' natural gas volume metrics for gas distribution operations and gas marketing services illustrate the effects of weather and customer demand for natural gas. Wholesale gas services' physical sales volumes represent the daily average natural gas volumes sold to its customers.

See RESULTS OF OPERATIONS herein for additional information on these operating metrics.

Seasonality of Results

Heating Season is the period from November through March when natural gas usage and operating revenues are generally higher as more customers are connected to the gas distribution systems and natural gas usage is higher in periods of colder weather. Occasionally in the summer, wholesale gas services' operating revenues are impacted due to peak usage by power generators in response to summer energy demands. Southern Company Gas' base operating expenses, excluding cost of natural gas, bad debt expense, and certain incentive compensation costs, are incurred relatively evenly throughout the year. Seasonality also affects the comparison of certain balance sheet items across quarters, including receivables, unbilled revenues, natural gas for sale, and notes payable. However, these items are comparable when reviewing Southern Company Gas' annual results. Operating results for the interim periods presented are not necessarily indicative of annual results and can vary significantly from quarter to quarter.

RESULTS OF OPERATIONS

Net Income (Loss)

Second Quarter 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$(80)	(163.3)	$(40)	(13.9)

Southern Company Gas' net loss for the second quarter 2018 was $31 million compared to net income of $49 million for the corresponding period in 2017. For year-to-date 2018, net income was $248 million compared to $288 million for the corresponding period in 2017. The decreases were primarily due to the $36 million pre-tax loss ($76 million after tax) on the disposition of Pivotal Home Solutions, a reserve for a settlement of class action litigation to facilitate the sale of Pivotal Home Solutions, derivative losses at wholesale gas services, disposition-related costs, and increased interest expense. These decreases were partially offset by additional revenues from infrastructure investments recovered through replacement programs less the associated increase in depreciation, as well as base rate changes at gas distribution operations, higher commercial activity at wholesale gas services, and revenues from the Dalton Pipeline, which was placed in service in August 2017. Also contributing to the decrease for year-to-date

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

2018 was a goodwill impairment charge of $42 million recorded during the first quarter 2018 in contemplation of the sale of Pivotal Home Solutions.

See Note (J) to the Condensed Financial Statements under "Southern Company Gas – Sale of Pivotal Home Solutions" herein for additional information.

Natural Gas Revenues, including Alternative Revenue Programs

Second Quarter 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$22	3.2	$100	4.5

In the second quarter 2018, natural gas revenues, including alternative revenue programs, were $706 million compared to $684 million for the corresponding period in 2017. For year-to-date 2018, natural gas revenues, including alternative revenue programs, were $2.3 billion compared to $2.2 billion for the corresponding period in 2017.

Details of the changes in natural gas revenues were as follows:

	Second Quarter 2018					Year-to-Date 2018
	(in millions)			(% change)		(in millions)			(% change)
Natural gas revenues – prior year	$	684				$	2,214
Estimated change resulting from –
Infrastructure replacement programs and base rate changes	38			5.6	%	48			2.2	%
Gas costs and other cost recovery	(4		)	(0.6	)%	(2		)	(0.1	)%
Weather	8			1.2	%	16			0.7	%
Wholesale gas services	(4		)	(0.6	)%	31			1.4	%
Other	(16		)	(2.4	)%	7			0.3	%
Natural gas revenues – current year	$	706		3.2	%	$	2,314		4.5	%

The increases in natural gas revenues in the second quarter and year-to-date 2018 were primarily related to continued infrastructure investments recovered through replacement programs and base rate changes at gas distribution operations. These changes include base rate increases as a result of rate cases, partially offset by revenue reductions for the impacts of the Tax Reform Legislation. See Note (B) to the Condensed Financial Statements herein under "Regulatory Matters – Southern Company Gas" for additional information.

Revenues associated with gas costs and other cost recovery decreased due to reduced natural gas prices during 2018 compared to the corresponding periods in 2017, partially offset by increased volumes of natural gas sold in 2018 as a result of colder weather. See "Cost of Natural Gas" herein for additional information.

Revenues increased due to colder weather in 2018 compared to the corresponding periods in 2017 that affected the utility customers in Illinois and the gas marketing services customers in Georgia and Illinois. See the weather discussion herein for additional information.

Revenues from wholesale gas services decreased in the second quarter 2018 primarily due to derivative losses, partially offset by increased commercial activity and increased for year-to-date 2018 primarily due to increased commercial activity, partially offset by derivative losses. See "Wholesale Gas Services" herein for additional information.

Natural gas distribution rates include provisions to adjust billings for fluctuations in natural gas costs. Therefore, gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas and do

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

not affect net income from gas distribution operations. See "Cost of Natural Gas" herein for additional information. Revenue impacts from weather and customer growth are described further below.

During Heating Season, natural gas usage and operating revenues are generally higher. Weather typically does not have a significant net income impact other than during the Heating Season. The following table presents the Heating Degree Days information for Illinois and Georgia, the primary locations where Southern Company Gas' operations are impacted by weather.

	Second Quarter			2018 vs. 2017		2018 vs. normal		Year-to-Date			2018 vs. 2017		2018 vs. normal
	Normal(*)	2018	2017	colder		colder		Normal(*)	2018	2017	colder		colder (warmer)
Illinois	628	767	555	38.2	%	22.1	%	3,698	3,809	3,110	22.5	%	3.0	%
Georgia	122	175	75	133.3	%	43.4	%	1,578	1,539	1,000	53.9	%	(2.5	)%

(*) Normal represents the 10-year average from January 1, 2008 through June 30, 2017 for Illinois at Chicago Midway International Airport and for Georgia at Atlanta Hartsfield-Jackson International Airport, based on information obtained from the National Oceanic and Atmospheric Administration, National Climatic Data Center.

Southern Company Gas hedged its exposure to warmer-than-normal weather in Illinois for gas distribution operations and in Illinois and Georgia for gas marketing services, which limited the negative income impacts reflected in the chart below.

	Gas Distribution Operations									Gas Marketing Services
	Second Quarter				Year-to-Date					Second Quarter					Year-to-Date
	2018		2017		2018		2017			2018		2017			2018			2017
	(in millions)									(in millions)
Pre-tax	$	4	$	1	$	2	$	(5	)	$	2	$	(3	)	$	(1	)	$	(10	)
After tax	3		1		2		(3		)	1		(2		)	(1		)	(6		)

The following table provides the number of customers served by Southern Company Gas at June 30, 2018 and 2017:

	June 30,
	2018		2017		2018 vs. 2017
	(in thousands, except market share %)				(% change)
Gas distribution operations(a)	4,609		4,573		0.8	%
Gas marketing services(b)
Energy customers(c)	696		768		(9.4	)%
Market share of energy customers in Georgia	29.4	%	29.1	%

(a) Includes total customers of approximately 407,000 and 403,000 at June 30, 2018 and 2017, respectively, related to Elizabethtown Gas, Elkton Gas, and Florida City Gas, which were sold subsequent to June 30, 2018. See Note (J) to the Condensed Financial Statements under "Southern Company Gas – Sale of Elizabethtown Gas and Elkton Gas" and " – Sale of Florida City Gas" herein for additional information.

(b) On June 4, 2018, Southern Company Gas completed the sale of Pivotal Home Solutions, which served approximately 1.2 million contracts prior to disposition. See Note (J) to the Condensed Financial Statements under "Southern Company Gas – Sale of Pivotal Home Solutions" herein for additional information.

(c) The decrease at June 30, 2018 is primarily due to approximately 70,000 fewer customers in Ohio contracted through an annual auction process to serve for 12 months beginning April 1, 2018. At June 30, 2017, there were approximately 140,000 customers in Ohio contracted through an annual auction process to serve for 12 months beginning April 1, 2017.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Southern Company Gas anticipates overall customer growth trends at the remaining four natural gas distribution utilities in gas distribution operations to continue as it expects continued improvement in the new housing market and low natural gas prices. Southern Company Gas uses a variety of targeted marketing programs to attract new customers and to retain existing customers.

Cost of Natural Gas

Second Quarter 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$(4)	(1.7)	$(2)	(0.2)

Natural gas distribution rates include provisions to adjust billings for fluctuations in natural gas costs. Therefore, gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas and do not affect net income from gas distribution operations. Cost of natural gas at gas distribution operations represented 84% of total cost of natural gas for both the second quarter and year-to-date 2018. For additional information, see MANAGEMENT'S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS – "Cost of Natural Gas and Other Sales" of Southern Company Gas in Item 7 of the Form 10-K and "Natural Gas Revenues" herein.

In the second quarter 2018, cost of natural gas was $228 million compared to $232 million for the corresponding period in 2017. The decrease reflects a 12% decrease in natural gas prices during the second quarter 2018 compared to the corresponding period in 2017, partially offset by an increase in the volume of natural gas sold in 2018 as a result of colder weather.

For year-to-date 2018, cost of natural gas was $949 million compared to $951 million for the corresponding period in 2017. The decrease reflects an 11% decrease in natural gas prices during year-to-date 2018 compared to the corresponding period in 2017, partially offset by an increase in volumes of natural gas sold in 2018 as a result of colder weather.

The following table details the volumes of natural gas sold during all periods presented.

	Second Quarter		2018 vs. 2017		Year-to-Date		2018 vs. 2017
	2018	2017			2018	2017
Gas distribution operations(mmBtu in millions)
Firm	119	102	16.7	%	434	365	18.9	%
Interruptible	25	23	8.7	%	49	48	2.1	%
Total	144	125	15.2	%	483	413	16.9	%
Gas marketing services(mmBtu in millions)
Firm:
Georgia	5	4	25.0	%	22	17	29.4	%
Illinois	2	2	—	%	8	7	14.3	%
Ohio	2	2	—	%	11	5	120.0	%
Other	1	1	—	%	2	3	(33.3	)%
Interruptible large commercial and industrial	3	3	—	%	7	7	—	%
Total	13	12	8.3	%	50	39	28.2	%
Wholesale gas services (mmBtu in millions/day)
Daily physical sales	6.4	6.2	3.2	%	6.6	6.4	3.1	%

167

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Other Operations and Maintenance Expenses

Second Quarter 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$24	11.2	$44	9.4

In the second quarter 2018, other operations and maintenance expenses were $238 million compared to $214 million for the corresponding period in 2017. The increase was primarily due to an $11 million reserve for a settlement of class action litigation to facilitate the sale of Pivotal Home Solutions, a $6 million increase in compensation and benefit costs, and $4 million of disposition-related costs.

For year-to-date 2018, other operations and maintenance expenses were $514 million compared to $470 million for the corresponding period in 2017. The increase was primarily due to an $11 million reserve for a settlement of class action litigation to facilitate the sale of Pivotal Home Solutions, a $22 million increase in compensation and benefit costs, a $12 million one-time increase for the adoption of a new paid time off policy to align with the Southern Company system, and $6 million of disposition-related costs. These increases were partially offset by an $8 million decrease in recoverable costs, primarily related to bad debt expense, at gas distribution operations. See Notes (B) and (J) to the Condensed Financial Statements under "General Litigation Matters – Southern Company Gas" and "Southern Company Gas – Sale of Pivotal Home Solutions," respectively, herein for additional information. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Other Matters" of Southern Company Gas in Item 7 of the Form 10-K for additional information on the new paid time off policy.

Depreciation and Amortization

Second Quarter 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$1	0.8	$11	4.5

In the second quarter 2018, depreciation and amortization was $126 million compared to $125 million for the corresponding period in 2017. For year-to-date 2018, depreciation and amortization was $255 million compared to $244 million for the corresponding period in 2017. These increases were primarily due to continued infrastructure investments recovered through replacement programs at gas distribution operations, partially offset by timing of amortization of intangible assets as a result of fair value adjustments in acquisition accounting at gas marketing services and ceasing recognition of depreciation and amortization on Pivotal Home Solutions' assets classified as held for sale and subsequently sold in the second quarter 2018.

Taxes Other Than Income Taxes

Second Quarter 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$4	9.1	$11	9.6

In the second quarter 2018, taxes other than income taxes were $48 million compared to $44 million for the corresponding period in 2017. For year-to-date 2018, taxes other than income taxes were $125 million compared to $114 million for the corresponding period in 2017. These increases primarily reflect an increase in revenue tax expenses as a result of higher revenues as well as payroll taxes related to benefits under the new paid time off policy.

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Other Matters" of Southern Company Gas in Item 7 of the Form 10-K for additional information on the new paid time off policy.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Goodwill Impairment

Second Quarter 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$—	N/A	$42	N/A

N/A - Not applicable

For year-to-date 2018, a goodwill impairment charge of $42 million was recorded during the first quarter 2018 in contemplation of the sale of Pivotal Home Solutions. See Note (A) to the Condensed Financial Statements under "Goodwill and Other Intangible Assets" and Note (J) to the Condensed Financial Statements under "Southern Company Gas – Sale of Pivotal Home Solutions" herein for additional information.

Loss on Disposition

Second Quarter 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$36	N/A	$36	N/A

N/A - Not applicable

The sale of Pivotal Home Solutions was structured as a stock sale for book purposes; however, both parties elected to treat it as an asset sale for tax purposes. The resulting increase in the book loss is offset by a reduction in deferred tax expense. See "Income Taxes" herein and Note (J) to the Condensed Financial Statements under "Southern Company Gas – Sale of Pivotal Home Solutions" herein for additional information.

Earnings from Equity Method Investments

Second Quarter 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$2	6.9	$6	8.8

In the second quarter 2018, earnings from equity method investments were $31 million compared to $29 million for the corresponding period in 2017. The increase was primarily due to higher earnings from SNG. For year-to-date 2018, earnings from equity method investments were $74 million compared to $68 million for the corresponding period in 2017. The increase was primarily due to higher earnings from SNG.

Interest Expense, Net of Amounts Capitalized

Second Quarter 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$11	22.9	$24	25.5

In the second quarter 2018, interest expense, net of amounts capitalized was $59 million compared to $48 million for the corresponding period in 2017. For year-to-date 2018, interest expense, net of amounts capitalized was $118 million compared to $94 million for the corresponding period in 2017. These increases were primarily due to additional interest expense on new debt issuances and additional commercial paper borrowings as well as a reduction in capitalized interest due to the Dalton Pipeline being placed in service in August 2017.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Other Income (Expense), Net

Second Quarter 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$(1)	(25.0)	$5	50.0

For year-to-date 2018, other income (expense), net was $15 million compared to $10 million for the corresponding period in 2017. The increase was primarily due to a $7 million gain from the settlement of a contractor litigation claim, partially offset by a decrease in interest income. See Note (B) to the Condensed Financial Statements under "Regulatory Matters – Southern Company Gas – Atlanta Gas Light's Pipeline Replacement Program" herein for additional information.

Income Taxes

Second Quarter 2018 vs. Second Quarter 2017		Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)	(% change)	(change in millions)	(% change)
$24	77.4	$(21)	(11.7)

In the second quarter 2018, income taxes were $55 million compared to $31 million for the corresponding period in 2017. The increase was primarily due to $40 million of income taxes associated with the sale of Pivotal Home Solutions, primarily due to goodwill not deductible for tax purposes and for which a deferred tax liability had not been recorded previously, partially offset by the reduction in deferred tax expense as a result of treating the sale as an asset sale for tax purposes. In addition, this increase was partially offset by lower pre-tax earnings as well as a lower federal income tax rate and the flowback of excess deferred taxes as a result of the Tax Reform Legislation.

For year-to-date 2018, income taxes were $159 million compared to $180 million for the corresponding period in 2017. The decrease was primarily due to lower pre-tax earnings as well as a lower federal income tax rate and the flowback of excess deferred taxes as a result of the Tax Reform Legislation. This decrease was partially offset by $40 million of income taxes recorded for the sale of Pivotal Home Solutions which includes the reduction in deferred tax expense as a result of treating the sale as an asset sale for tax purposes.

See Notes (H) and (J) to the Condensed Financial Statements under "Effective Tax Rate" and "Southern Company Gas – Sale of Pivotal Home Solutions," respectively, herein for additional information.

Performance and Non-GAAP Measures

Adjusted operating margin is a non-GAAP measure that is calculated as operating revenues less cost of natural gas, cost of other sales, and revenue tax expense. Adjusted operating margin excludes other operations and maintenance expenses, depreciation and amortization, taxes other than income taxes, goodwill impairment, and loss on disposition, which are included in the calculation of operating income as calculated in accordance with GAAP and reflected in the statements of income. The presentation of adjusted operating margin is believed to provide useful information regarding the contribution resulting from customer growth at gas distribution operations since the cost of natural gas and revenue tax expense can vary significantly and are generally billed directly to customers. Southern Company Gas further believes that utilizing adjusted operating margin at gas marketing services, wholesale gas services, and gas midstream operations allows it to focus on a direct measure of adjusted operating margin before overhead costs. The applicable reconciliation of operating income to adjusted operating margin is provided herein.

Adjusted operating margin should not be considered an alternative to, or a more meaningful indicator of, Southern Company Gas' operating performance than operating income as determined in accordance with GAAP. In addition, Southern Company Gas' adjusted operating margin may not be comparable to similarly titled measures of other companies.

170

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

	Second Quarter 2018			Second Quarter 2017			Year-to-Date 2018			Year-to-Date 2017
	(in millions)
Operating Income	$	49		$	95		$	436		$	484
Other operating expenses(a)	448			383			972			828
Revenue taxes(b)	(23		)	(18		)	(73		)	(65		)
Adjusted Operating Margin	$	474		$	460		$	1,335		$	1,247

(a) Includes other operations and maintenance, depreciation and amortization, taxes other than income taxes, goodwill impairment, and loss on disposition.

(b) Nicor Gas' revenue tax expenses, which are passed through directly to customers.

Segment Information

Adjusted operating margin, operating expenses, and net income for each segment is illustrated in the tables below. See Note (L) to the Condensed Financial Statements herein for additional information.

	Second Quarter 2018									Second Quarter 2017
	Adjusted Operating Margin(a)			Operating Expenses(a)(b)			Net Income (Loss)(b)			Adjusted Operating Margin(a)			Operating Expenses(a)			Net Income (Loss)
	(in millions)									(in millions)
Gas distribution operations	$	429		$	296		$	68		$	409		$	284		$	54
Gas marketing services	48			87			(76		)	57			48			4
Wholesale gas services	(16		)	14			(21		)	(13		)	14			(17		)
Gas midstream operations	13			14			14			7			13			9
All other	1			15			(16		)	3			9			(1		)
Intercompany eliminations	(1		)	(1		)	—			(3		)	(3		)	—
Consolidated	$	474		$	425		$	(31	)	$	460		$	365		$	49

(a) Adjusted operating margin and operating expenses are adjusted for Nicor Gas revenue tax expenses, which are passed through directly to customers.

(b) Operating expenses for gas marketing services include the loss on disposition. Net loss for gas marketing services includes the loss on disposition of assets and the associated income tax expense. See Note (J) to the Condensed Financial Statements under "Southern Company Gas – Sale of Pivotal Home Solutions" herein for additional information.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

	Year-to-Date 2018									Year-to-Date 2017
	Adjusted Operating Margin(a)			Operating Expenses(a)(b)(c)			Net Income (Loss)(c)			Adjusted Operating Margin(a)			Operating Expenses(a)			Net Income
	(in millions)									(in millions)
Gas distribution operations	$	986		$	620		$	216		$	951		$	599		$	171
Gas marketing services	175			181			(63		)	162			101			35
Wholesale gas services	147			36			83			118			29			51
Gas midstream operations	29			29			38			16			25			25
All other	2			37			(26		)	5			14			6
Intercompany eliminations	(4		)	(4		)	—			(5		)	(5		)	—
Consolidated	$	1,335		$	899		$	248		$	1,247		$	763		$	288

(a) Adjusted operating margin and operating expenses are adjusted for Nicor Gas revenue tax expenses, which are passed through directly to customers.

(b) Operating expenses for gas marketing services include a goodwill impairment charge of $42 million recorded during the first quarter 2018 in contemplation of the sale of Pivotal Home Solutions. See Note (A) to the Condensed Financial Statements under "Goodwill and Other Intangible Assets" and Note (J) to the Condensed Financial Statements under "Southern Company Gas – Sale of Pivotal Home Solutions" herein for additional information.

(c) Operating expenses for gas marketing services include the loss on disposition. Net loss for gas marketing services includes the loss on disposition and the associated income tax expense. See Note (J) to the Condensed Financial Statements under "Southern Company Gas – Sale of Pivotal Home Solutions" herein for additional information.

Gas Distribution Operations

Gas distribution operations is the largest component of Southern Company Gas' business and is subject to regulation and oversight by agencies in each of the states it serves. These agencies approve natural gas rates designed to provide Southern Company Gas with the opportunity to generate revenues to recover the cost of natural gas delivered to its customers and its fixed and variable costs, including depreciation, interest, maintenance, taxes, and overhead costs, and to earn a reasonable return on its investments.

With the exception of Atlanta Gas Light, Southern Company Gas' second largest utility that operates in a deregulated natural gas market and has a straight-fixed-variable rate design that minimizes the variability of its revenues based on consumption, the earnings of the natural gas distribution utilities can be affected by customer consumption patterns that are a function of weather conditions, price levels for natural gas, and general economic conditions that may impact customers' ability to pay for natural gas consumed. Southern Company Gas has various weather mechanisms, such as weather normalization mechanisms and weather derivative instruments, that limit its exposure to weather changes within typical ranges in its natural gas distribution utilities' service territories.

Second Quarter 2018 vs. Second Quarter 2017

In the second quarter 2018, net income increased $14 million, or 25.9%, compared to the corresponding period in 2017. This increase primarily relates to an increase of $20 million in adjusted operating margin and a decrease in income tax expense of $11 million, partially offset by an increase of $12 million in operating expenses and an increase of $5 million in interest expense, net of amounts capitalized. The increase in adjusted operating margin primarily reflects $39 million in additional revenue from continued infrastructure investments recovered through replacement programs and base rates. The decrease in income taxes is primarily due to a lower federal income tax rate and the flowback of excess deferred taxes as a result of the Tax Reform Legislation. The increase in operating expenses primarily reflects additional depreciation due to additional assets placed in service and increased compensation and benefit costs, partially offset by a decrease in recoverable costs, primarily related to bad debt expense. The increase in interest expense includes the impact of the issuance of first mortgage bonds at Nicor Gas in 2017 and additional commercial paper borrowings during the second quarter 2018.

172

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Year-to-Date 2018 vs. Year-to-Date 2017

For year-to-date 2018, net income increased $45 million, or 26.3%, compared to the corresponding period in 2017. This increase primarily relates to an increase of $35 million in adjusted operating margin, an increase of $4 million in other income (expense), net, and a decrease in income tax expense of $38 million, partially offset by an increase of $21 million in operating expenses and an increase of $11 million in interest expense, net of amounts capitalized. The increase in adjusted operating margin primarily reflects $86 million in additional revenue from continued infrastructure investments recovered through replacement programs and base rates, partially offset by revenue deferrals totaling $38 million for regulatory liabilities associated with the Tax Reform Legislation impacts. The increase in other income (expense), net primarily reflects a gain from the settlement of a contractor litigation claim in 2018, partially offset by a decrease in interest income. The decrease in income taxes is primarily due to a lower federal income tax rate and the flowback of excess deferred taxes as a result of the Tax Reform Legislation. The increase in operating expenses primarily reflects additional depreciation due to additional assets placed in service and increased compensation and benefit costs, partially offset by a decrease in recoverable costs, primarily related to bad debt expense. The increase in interest expense includes the impact of the issuance of first mortgage bonds at Nicor Gas in 2017 and additional commercial paper borrowings during year-to-date 2018.

Gas Marketing Services

Gas marketing services consists of several businesses that provide energy-related products and services to natural gas markets, including warranty sales. Gas marketing services is weather sensitive and uses a variety of hedging strategies, such as weather derivative instruments and other risk management tools, to partially mitigate potential weather impacts. On June 4, 2018, Southern Company Gas completed the sale of Pivotal Home Solutions to American Water Enterprises LLC. See Note (J) under "Southern Company Gas" herein for additional information.

Second Quarter 2018 vs. Second Quarter 2017

In the second quarter 2018, net income decreased $80 million compared to the corresponding period in 2017. This decrease was driven by a $76 million loss on the sale of Pivotal Home Solutions, which included $40 million of income tax expense on goodwill not deductible for tax purposes and for which a deferred tax liability had not been recorded previously and an $11 million pre-tax reserve for a settlement of class action litigation to facilitate the sale of Pivotal Home Solutions. See Notes (B) and (J) to the Condensed Financial Statements under "General Litigation Matters – Southern Company Gas" and "Southern Company Gas – Sale of Pivotal Home Solutions," respectively, herein for additional information.

Year-to-Date 2018 vs. Year-to-Date 2017

For year-to-date 2018, net income decreased $98 million compared to the corresponding period in 2017. This decrease was driven by a $76 million loss on the sale of Pivotal Home Solutions, which included $40 million of income tax expense on goodwill not deductible for tax purposes and for which a deferred tax liability had not been recorded previously, a $42 million goodwill impairment charge recorded in contemplation of the sale of Pivotal Home Solutions, and an $11 million pre-tax reserve for a settlement of class action litigation to facilitate the sale of Pivotal Home Solutions, partially offset by an increase in adjusted operating margin of $13 million, a decrease in depreciation and amortization of $10 million, primarily due to the timing of amortization of intangible assets as a result of fair value adjustments recorded during acquisition accounting as well as the sale of Pivotal Home Solutions, and a decrease in the federal income tax rate. Adjusted operating margin increased by $13 million due to $9 million for colder weather in 2018, $6 million for fixed and guaranteed bill revenue as a result of adopting a new revenue recognition standard, and $2 million from energy customers contracted through an annual auction process to serve for 12 months beginning April 1, 2017, partially offset by the sale of Pivotal Home Solutions during the second quarter 2018. See Note (A) under "Recently Adopted Accounting Standards" and "Goodwill and Other Intangible Assets," Note (B) under "General Litigation Matters – Southern Company Gas," and Note (J) under "Southern Company Gas – Sale of Pivotal Home Solutions" to the Condensed Financial Statements herein for additional information.

173

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Wholesale Gas Services

Wholesale gas services is involved in asset management and optimization, storage, transportation, producer and peaking services, natural gas supply, natural gas services, and wholesale gas marketing. Southern Company Gas has positioned the business to generate positive economic earnings on an annual basis even under low volatility market conditions that can result from a number of factors. When market price volatility increases, wholesale gas services is well positioned to capture significant value and generate stronger results. Operating expenses primarily reflect employee compensation and benefits.

Second Quarter 2018 vs. Second Quarter 2017

In the second quarter 2018, net income decreased $4 million, or 23.5%, compared to the corresponding period in 2017. This decrease was primarily due to interest incurred on a promissory note issued during 2018 to meet working capital needs.

Year-to-Date 2018 vs. Year-to-Date 2017

For year-to-date 2018, net income increased $32 million, or 62.7%, compared to the corresponding period in 2017. This increase primarily relates to a $29 millionincrease in adjusted operating margin and a decrease of $11 million in income tax expense, partially offset by an increase of $7 million in operating expenses. Details of the increase in adjusted operating margin are provided in the table below. The increase in operating expenses primarily reflects higher compensation and benefit expense. The decrease in income tax expense was driven by a lower federal income tax rate, partially offset by higher pretax earnings.

	Second Quarter 2018			Second Quarter 2017			Year-to-Date 2018			Year-to-Date 2017
	(in millions)
Commercial activity recognized	$	17		$	(18	)	$	189		$	69
Gain (loss) on storage derivatives	—			17			1			18
Gain (loss) on transportation and forward commodity derivatives	(28		)	(2		)	(44		)	37
LOCOM adjustments, net of current period recoveries	—			(1		)	(3		)	(1		)
Purchase accounting adjustments to fair value inventory and contracts	(5		)	(9		)	4			(5		)
Adjusted operating margin	$	(16	)	$	(13	)	$	147		$	118

Change in Commercial Activity

The increase in commercial activity in the second quarter and year-to-date 2018 compared to the corresponding periods in 2017 was primarily due to natural gas price volatility that was generated by favorable weather and a corresponding increase in power generation volumes coupled with decreased natural gas supply.

Change in Storage and Transportation Derivatives

Volatility in the natural gas market arises from a number of factors, such as weather fluctuations or changes in supply or demand for natural gas in different regions of the U.S. The volatility of natural gas commodity prices has a significant impact on Southern Company Gas' customer rates, long-term competitive position against other energy sources, and the ability of wholesale gas services to capture value from locational and seasonal spreads. Forward storage or time spreads applicable to the locations of wholesale gas services' specific storage positions in 2018 remained consistent with the 2017 spreads. Transportation and forward commodity derivative losses in 2018 are primarily the result of widening transportation spreads due to favorable weather, which impacted forward prices at natural gas receipt and delivery points, primarily in the Northeast and Midwest regions.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Withdrawal Schedule and Physical Transportation Transactions

The expected natural gas withdrawals from storage and expected offset to prior hedge losses/gains associated with the transportation portfolio of wholesale gas services are presented in the following table, along with the net operating revenues expected at the time of withdrawal from storage and the physical flow of natural gas between contracted transportation receipt and delivery points. Wholesale gas services' expected net operating revenues exclude storage and transportation demand charges, as well as other variable fuel, withdrawal, receipt, and delivery charges, and exclude estimated profit sharing under asset management agreements. Further, the amounts that are realizable in future periods are based on the inventory withdrawal schedule, planned physical flow of natural gas between the transportation receipt and delivery points, and forward natural gas prices at June 30, 2018. A portion of wholesale gas services' storage inventory and transportation capacity is economically hedged with futures contracts, which results in the realization of substantially fixed net operating revenues.

	Storage withdrawal schedule
	Total storage(a)	Expected net operating gains(b)		Physical transportation transactions – expected net operating gains(c)
	(in mmBtu in millions)	(in millions)		(in millions)
2018	25.9	$	4	$	10
2019 and thereafter	9.0	4		34
Total at June 30, 2018	34.9	$	8	$	44

(a) At June 30, 2018, the WACOG of wholesale gas services' expected natural gas withdrawals from storage was $2.51 per mmBtu.

(b) Represents expected operating gains from planned storage withdrawals associated with existing inventory positions and could change as wholesale gas services adjusts its daily injection and withdrawal plans in response to changes in future market conditions and forward NYMEX price fluctuations.

(c) Represents the periods associated with the transportation derivative gains and (losses) during which the derivatives will be settled and the physical transportation transactions will occur that offset the derivative gains and losses that were previously recognized.

The unrealized storage and transportation derivative gains do not change the underlying economic value of wholesale gas services' storage and transportation positions and will be reversed when the related transactions occur and are recognized. For more information on wholesale gas services' energy marketing and risk management activities, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of Southern Company Gas in Item 7 of the Form 10-K.

Gas Midstream Operations

Gas midstream operations consists primarily of gas pipeline investments, with storage and fuels also aggregated into this segment. Gas pipeline investments include SNG, Horizon Pipeline, Atlantic Coast Pipeline, PennEast Pipeline, Dalton Pipeline, and Magnolia Enterprise Holdings, Inc. See Note (K) to the Condensed Financial Statements herein and Note 4 to the financial statements of Southern Company Gas in Item 8 of the Form 10-K for additional information.

Second Quarter 2018 vs. Second Quarter 2017

In the second quarter 2018, net income increased $5 million, or 55.6%, compared to the corresponding period in 2017. This increase primarily relates to a $6 millionincrease in adjusted operating margin primarily due to the Dalton Pipeline being placed in service in August 2017 and a $2 million net increase in earnings from equity method investments in SNG, PennEast Pipeline, and Horizon Pipeline, partially offset by an increase in interest expense due to lower amounts capitalized after the Dalton Pipeline was placed in service.

Year-to-Date 2018 vs. Year-to-Date 2017

For year-to-date 2018, net income increased $13 million, or 52.0%, compared to the corresponding period in 2017. This increase primarily relates to a $13 millionincrease in adjusted operating margin primarily due to the Dalton

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Pipeline being placed in service in August 2017, lower costs at the storage facilities, and a $6 million net increase in earnings from equity method investments in SNG, PennEast Pipeline, and Horizon Pipeline, partially offset by an increase in interest expense due to lower interest capitalized after the Dalton Pipeline was placed in service.

All Other

All other includes Southern Company Gas' investment in Triton, AGL Services Company, and Southern Company Gas Capital, as well as various corporate operating expenses that are not allocated to the reportable segments and interest income (expense) associated with affiliate financing arrangements.

Second Quarter 2018 vs. Second Quarter 2017

In the second quarter 2018, net income decreased $15 million compared to the corresponding period in 2017. This decrease primarily reflects a $6 millionincrease in operating expenses that includes $4 million of disposition-related costs, a $2 million increase in interest expense, net of amounts capitalized primarily due to new debt issuances and additional commercial paper borrowings, and a $4 million increase in income taxes due to tax allocation changes.

Year-to-Date 2018 vs. Year-to-Date 2017

For year-to-date 2018, net income decreased $32 million compared to the corresponding period in 2017. This decrease primarily reflects a $23 million increase in operating expenses and a $6 million increase in interest expense. The increase in operating expenses primarily reflects a $12 million increase in compensation expense resulting from the adoption of the new paid time off policy and $6 million of disposition-related costs. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Other Matters" of Southern Company Gas in Item 7 of the Form 10-K for additional information on the new paid time off policy. The increase in interest expense was primarily associated with new debt issuances and additional commercial paper borrowings.

Segment Reconciliations

Reconciliations of operating income to adjusted operating margin for the second quarter2018 and 2017 are reflected in the following tables. See Note (L) to the Condensed Financial Statements herein for additional information.

	Second Quarter 2018
	Gas Distribution Operations			Gas Marketing Services			Wholesale Gas Services			Gas Midstream Operations			All Other			Intercompany Elimination			Consolidated
	(in millions)
Operating Income (Loss)	$	133		$	(39	)	$	(30	)	$	(1	)	$	(14	)	$	—		$	49
Other operating expenses(a)	319			87			14			14			15			(1		)	448
Revenue tax expense(b)	(23		)	—			—			—			—			—			(23		)
Adjusted Operating Margin	$	429		$	48		$	(16	)	$	13		$	1		$	(1	)	$	474

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	Second Quarter 2017
	Gas Distribution Operations			Gas Marketing Services		Wholesale Gas Services			Gas Midstream Operations			All Other			Intercompany Elimination			Consolidated
	(in millions)
Operating Income (Loss)	$	125		$	9	$	(27	)	$	(6	)	$	(6	)	$	—		$	95
Other operating expenses(a)	302			48		14			13			9			(3		)	383
Revenue tax expense(b)	(18		)	—		—			—			—			—			(18		)
Adjusted Operating Margin	$	409		$	57	$	(13	)	$	7		$	3		$	(3	)	$	460

	Year-to-Date 2018
	Gas Distribution Operations			Gas Marketing Services			Wholesale Gas Services		Gas Midstream Operations		All Other			Intercompany Elimination			Consolidated
	(in millions)
Operating Income (Loss)	$	366		$	(6	)	$	111	$	—	$	(35	)	$	—		$	436
Other operating expenses(a)	693			181			36		29		37			(4		)	972
Revenue tax expense(b)	(73		)	—			—		—		—			—			(73		)
Adjusted Operating Margin	$	986		$	175		$	147	$	29	$	2		$	(4	)	$	1,335

	Year-to-Date 2017
	Gas Distribution Operations			Gas Marketing Services		Wholesale Gas Services		Gas Midstream Operations			All Other			Intercompany Elimination			Consolidated
	(in millions)
Operating Income (Loss)	$	352		$	61	$	89	$	(9	)	$	(9	)	$	—		$	484
Other operating expenses(a)	664			101		29		25			14			(5		)	828
Revenue tax expense(b)	(65		)	—		—		—			—			—			(65		)
Adjusted Operating Margin	$	951		$	162	$	118	$	16		$	5		$	(5	)	$	1,247

(a) Includes other operations and maintenance, depreciation and amortization, taxes other than income taxes, goodwill impairment, and loss on disposition.

(b) Nicor Gas' revenue tax expenses, which are passed through directly to customers.

FUTURE EARNINGS POTENTIAL

The results of operations discussed above are not necessarily indicative of Southern Company Gas' future earnings potential. The level of Southern Company Gas' future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Southern Company Gas' primary business of natural gas distribution and its complementary businesses in the gas marketing services, wholesale gas services, and gas midstream operations sectors. These factors include Southern Company Gas' ability to maintain a constructive regulatory environment that allows for the timely recovery of prudently-incurred costs, the completion and subsequent operation of ongoing infrastructure and other construction projects, creditworthiness of customers, its ability to optimize its transportation and storage positions, and its ability to re-contract storage rates at favorable prices.

Future earnings will be driven by customer growth and are subject to a variety of other factors. These factors include weather, competition, new energy contracts with other utilities and other wholesale customers, energy conservation practiced by customers, the use of alternative energy sources by customers, the price of natural gas, the price elasticity of demand, and the rate of economic growth or decline in Southern Company Gas' service territories.

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Demand for natural gas is primarily driven by the pace of economic growth that 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 its gas marketing services and wholesale gas services segments 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. Over the longer term, volatility is expected to be low to moderate and locational and/or transportation spreads are expected to decrease as new pipelines are built to reduce the existing supply constraints in the shale areas of the Northeast U.S. To the extent these pipelines are delayed or not built, volatility could increase. Additional economic factors may contribute to this environment, including a significant drop in oil and natural gas prices, which could lead to consolidation of natural gas producers or reduced levels of natural gas production. Further, if economic conditions continue to improve, including the new housing market, the demand for natural gas may increase, which may cause natural gas prices to rise and drive higher volatility in the natural gas markets on a longer-term basis.

As part of its business strategy, Southern Company Gas regularly considers and evaluates joint development arrangements as well as acquisitions and dispositions of businesses and assets.

On June 4, 2018, Southern Company Gas completed the stock sale of Pivotal Home Solutions to American Water Enterprises LLC. For year-to-date 2018, net income attributable to Pivotal Home Solutions, exclusive of the loss on the disposition and the related goodwill impairment charge, was immaterial. Southern Company Gas and American Water Enterprises LLC entered into a transition services agreement whereby Southern Company Gas will provide certain administrative and operational services through no later than February 3, 2019.

On July 1, 2018, a Southern Company Gas subsidiary, Pivotal Utility Holdings, completed the sales of the assets of two of its natural gas distribution utilities, Elizabethtown Gas and Elkton Gas, to South Jersey Industries, Inc. For year-to-date 2018, net income attributable to Elizabethtown Gas and Elkton Gas was $26 million. However, due to the seasonal nature of the natural gas business and other factors including, but not limited to, weather, regulation, competition, customer demand, and general economic conditions, the year-to-date 2018 net income is not necessarily indicative of the results to be expected for any other period. Southern Company Gas and South Jersey Industries, Inc. entered into transition services agreements whereby Southern Company Gas will provide certain administrative and operational services through no later than January 31, 2020.

On July 29, 2018, Southern Company Gas and its wholly-owned direct subsidiary, NUI Corporation, completed the stock sale of Pivotal Utility Holdings, which primarily consisted of Florida City Gas, to NextEra Energy. For year-to-date 2018, net income attributable to Florida City Gas was $8 million. However, due to the seasonal nature of the natural gas business and other factors including, but not limited to, weather, regulation, competition, customer demand, and general economic conditions, the year-to-date 2018 net income is not necessarily indicative of the results to be expected for any other period. Southern Company Gas and NextEra Energy entered into a transition services agreement whereby Southern Company Gas will provide certain administrative and operational services through no later than July 29, 2020.

See Note (J) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information on these dispositions. See OVERVIEW – "Seasonality of Results" for additional information on seasonality.

Environmental Matters

New or revised environmental laws and regulations could affect many areas of Southern Company Gas' operations. The impact of any such changes cannot be determined at this time. Environmental compliance costs could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Further, increased costs that are recovered through regulated rates could contribute to reduced demand for natural gas, which could negatively affect results of operations, cash flows, and financial condition. Additionally, many commercial and industrial customers may also be affected by existing and future environmental requirements, which for some may have the potential to ultimately affect their demand for natural gas. See Note (B) under "Environmental Matters–

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Environmental Remediation" to the Condensed Financial Statements herein and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Southern Company Gas in Item 7 and Note 3 to the financial statements of Southern Company Gas under "Environmental Matters" in Item 8 of the Form 10-K for additional information.

Regulatory Matters

See Note 3 to the financial statements of Southern Company Gas under "Regulatory Matters" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Southern Company Gas" herein for additional information regarding Southern Company Gas' regulatory matters.

Riders

On April 19, 2018, the Illinois Commission approved Nicor Gas' variable income tax adjustment rider. This rider provides for refund or recovery of changes in income tax expense that result from income tax rates that differ from those used in Nicor Gas' last rate case. Customer refunds began on July 1, 2018 related to the January 1, 2018 through May 4, 2018 impacts of the Tax Reform Legislation. The impact of the Tax Reform Legislation subsequent to May 4, 2018 was addressed in Nicor Gas' approved rehearing request discussed herein under "Settled Base Rate Cases."

Natural Gas Cost Recovery

Southern Company Gas has established natural gas cost recovery rates approved by the relevant state regulatory agencies in the states in which it serves. Natural gas cost recovery revenues are adjusted for differences in actual recoverable natural gas costs and amounts billed in current regulated rates. Changes in the billing factor will not have a significant effect on Southern Company Gas' revenues or net income, but will affect cash flows.

Base Rate Cases

Settled Base Rate Cases

On February 23, 2018, Atlanta Gas Light revised its annual base rate filing to reflect the impacts of the Tax Reform Legislation and requested a $16 million rate reduction in 2018. On May 15, 2018, the Georgia PSC approved a stipulation for Atlanta Gas Light's annual base rates to remain at the 2017 level for 2018 and 2019, with customer credits of $8 million in each of July 2018 and October 2018 to reflect the impacts of the Tax Reform Legislation. The Georgia PSC maintained Atlanta Gas Light's previously authorized earnings band based on a ROE between 10.55% and 10.95% and increased the allowed equity ratio by 4% to an equity ratio of 55% to address the negative cash flow and credit metric impacts of the Tax Reform Legislation. Additionally, Atlanta Gas Light is required to file a traditional base rate case on or before June 1, 2019 for rates effective January 1, 2020.

On May 2, 2018, the Illinois Commission approved Nicor Gas' rehearing request for revised base rates to incorporate the reduction in the federal income tax rate as a result of the Tax Reform Legislation. The resulting decrease of approximately $44 million in annual base rate revenues became effective May 5, 2018. Nicor Gas' previously-authorized capital structure and ROE of9.8% were not addressed in the rehearing and remain unchanged. The impact of the Tax Reform Legislation prior to May 5, 2018 was addressed in the variable income tax rider discussed herein under "Riders."

Pending Base Rate Case

On February 15, 2018, Chattanooga Gas filed a general base rate case with the Tennessee Public Utility Commission (PUC) requesting a $7 million increase in annual base rate revenues. The requested increase, which, in accordance with a Tennessee PUC order, incorporated the effects of the Tax Reform Legislation, was based on a projected test year ending June 30, 2019 and a ROE of 11.25%. The Tennessee PUC is expected to rule on the requested increase in the third quarter 2018.

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

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Other

The Virginia Commission issued an order effective January 1, 2018 that requires utilities in the state to defer as a regulatory liability the impact of the Tax Reform Legislation, including the reduction in the corporate income tax rate to 21% and the impact of the flowback of excess deferred income taxes.

On April 25, 2018, the Virginia Commission issued an order indicating that any proposal beyond a proposed base rate reduction to reflect the cost savings from the Tax Reform Legislation must be made through a general base rate case. Virginia Natural Gas expects to address the cost savings from the Tax Reform Legislation in the third quarter 2018 by filing an annual information form. The Virginia Commission is expected to rule on the impact of the Tax Reform Legislation by the first half of 2019. The ultimate outcome of this matter cannot be determined at this time.

Asset Management Agreements

Upon closing the sales of Elizabethtown Gas and Elkton Gas, an affiliate of South Jersey Industries, Inc. assumed the asset management agreements with wholesale gas services for Elizabethtown Gas and Elkton Gas. See Note (J) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information on these dispositions. For additional information, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Asset Management Agreements" of Southern Company Gas in Item 7 of the Form 10-K.

Regulatory Infrastructure Programs

Southern Company Gas is engaged in various infrastructure programs that update or expand its gas distribution systems to improve reliability and help ensure the safety of its utility infrastructure and recovers in rates its investment and a return associated with these infrastructure programs. Excluding the natural gas distribution utilities sold subsequent to June 30, 2018, infrastructure expenditures incurred in the first six months of 2018 were as follows:

Utility	Program	Year-to-Date 2018
		(in millions)
Nicor Gas	Investing in Illinois	$	135
Atlanta Gas Light	Georgia Rate Adjustment Mechanism (GRAM) infrastructure spending	139
Virginia Natural Gas	Steps to Advance Virginia's Energy	24
Total		$	298

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Infrastructure Replacement Programs and Capital Projects" of Southern Company Gas in Item 7 and Note 3 to the financial statements of Southern Company Gas under "Regulatory Matters – Regulatory Infrastructure Programs" in Item 8 of the Form 10-K for additional information.

Income Tax Matters

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters" of Southern Company Gas in Item 7 of the Form 10-K and FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk," Note (B) to the Condensed Financial Statements under "Regulatory Matters – Southern Company Gas," and Note (H) to the Condensed Financial Statements herein for information regarding the Tax Reform Legislation and related regulatory actions.

Other Matters

Southern Company Gas is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Southern Company Gas is subject to certain claims and legal actions arising in the ordinary course of business. The ultimate outcome of such pending or potential litigation or regulatory matters

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cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Southern Company Gas' financial statements. See Note (B) to the Condensed Financial Statements herein for a discussion of various other contingencies and regulatory matters, and other matters being litigated which may affect future earnings potential.

Southern Company Gas owns a 50% interest in a planned LNG liquefaction and storage facility in Jacksonville, Florida. Once construction is complete and the facility is operational, it will be outfitted with a 2.0 million gallon storage tank with the capacity to produce in excess of 120,000 gallons of LNG per day. It is expected to be operational in the third quarter 2018. The ultimate outcome of this matter cannot be determined at this time.

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

Southern Company Gas prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Southern Company Gas 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 Gas' 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 Gas in Item 7 of the Form 10-K for a complete discussion of Southern Company Gas' critical accounting policies and estimates.

Recently Issued Accounting Standards

See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Recently Issued Accounting Standards" of Southern Company Gas in Item 7 of the Form 10-K for additional information regarding ASU No. 2016-02, Leases (Topic 842). See Note (A) to the Condensed Financial Statements herein for information regarding Southern Company Gas' recently adopted accounting standards.

FINANCIAL CONDITION AND LIQUIDITY

Overview

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Southern Company Gas in Item 7 of the Form 10-K for additional information. Southern Company Gas' financial condition remained stable at June 30, 2018. Southern Company Gas 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.

By regulation, Nicor Gas is restricted, to the extent of its retained earnings balance, in the amount it can dividend or loan to affiliates and is not permitted to make money pool loans to affiliates. Prior to the disposition of Elizabethtown Gas, the New Jersey BPU restricted the amount Elizabethtown Gas could dividend to its parent company to 70% of its quarterly net income. At June 30, 2018, the amount of subsidiary retained earnings and net income restricted to dividend totaled $796 million. These restrictions did not have any impact on Southern Company Gas' ability to meet its cash obligations. Subsequent to the disposition of Elizabethtown Gas, management does not expect the remaining restriction to materially impact Southern Company Gas' ability to meet its currently anticipated cash obligations.

Net cash provided from operating activities totaled $1.3 billion for the first six months of 2018, an increase of $169 million from the corresponding period in 2017. The increase was primarily due to increased volumes of natural gas sold during the first six months of 2018 as a result of colder weather compared to the prior year, partially offset by higher income tax payments. Net cash used for investing activities totaled $381 million for the first six months of 2018 primarily due to gross property additions related to capital expenditures for infrastructure investments

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recovered through replacement programs at gas distribution operations and capital contributed to equity method investments in pipelines, partially offset by proceeds from the disposition of Pivotal Home Solutions. Net cash used for financing activities totaled $940 million for the first six months of 2018 primarily due to net repayments of commercial paper borrowings, the redemption of gas facility revenue bonds, and a common stock dividend payment to 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 2018 include the reclassification of $2.3 billion and $412 million in total assets and liabilities held for sale, respectively, associated with Elizabethtown Gas, Elkton Gas, and Florida City Gas as described in Note (J) to the Condensed Financial Statements herein under "Southern Company Gas" and "Assets Held for Sale," a decrease of $295 million in natural gas for sale, net of temporary LIFO liquidation, due to the use of stored natural gas, and a $515 million decrease in notes payable primarily related to net repayments of commercial paper borrowings. Other significant balance sheet changes include decreases of $71 million in accounts payable as well as $156 million and $61 million in energy marketing receivables and payables, respectively, due to lower natural gas prices and an increase of $462 million in total property, plant, and equipment primarily due to capital expenditures for rate base investments and pre-approved rider and infrastructure investments recovered through replacement programs.

Capital Requirements and Contractual Obligations

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Southern Company Gas in Item 7 of the Form 10-K for a description of Southern Company Gas' capital requirements and contractual obligations. Approximately $155 million will be required through June 30, 2019 to fund maturities of long-term debt. See "Sources of Capital" herein for additional information.

The regulatory infrastructure programs and other construction programs are subject to periodic review and revision, and actual costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in FERC rules and regulations; state regulatory approvals; changes in legislation; the cost and efficiency of 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. See Note 3 to the consolidated financial statements of Southern Company Gas in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for information regarding additional factors that may impact infrastructure investment expenditures.

Sources of Capital

Southern Company Gas plans to obtain the funds to meet its future capital needs through operating cash flows, external securities issuances, borrowings from financial institutions, and borrowings and equity contributions from Southern Company. In addition, Southern Company Gas plans to utilize the proceeds from the dispositions of Elizabethtown Gas, Elkton Gas, Florida City Gas, and Pivotal Home Solutions to pay the income taxes resulting from the sales, to retire existing debt, and for general corporate purposes. However, the amount, type, and timing of any future financings, if needed, depend upon prevailing market conditions, regulatory approval, and other factors. The issuance of securities by Nicor Gas is generally subject to the approval of the Illinois Commission. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Southern Company Gas in Item 7 of the Form 10-K for additional information.

The assets and liabilities associated with Elizabethtown Gas, Elkton Gas, and Florida City Gas are classified as held for sale and recorded as current assets and liabilities on the balance sheet at June 30, 2018 as described in Note (J) to the Condensed Financial Statements herein under "Southern Company Gas" and "Assets Held for Sale." Excluding the assets and liabilities classified as held for sale, Southern Company Gas' current liabilities exceeded current assets by $1.3 billion primarily as a result of $1.0 billion in notes payable. Southern Company Gas' current liabilities frequently exceed current assets because of commercial paper borrowings used to fund daily operations, scheduled maturities of long-term debt, and significant seasonal fluctuations in cash needs. Southern Company Gas

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intends to utilize operating cash flows, external securities issuances, borrowings from financial institutions, borrowings and equity contributions from Southern Company, and the proceeds from its dispositions to fund its short-term capital needs. Southern Company Gas has substantial cash flow from operating activities and access to the capital markets and financial institutions to meet liquidity needs.

At June 30, 2018, Southern Company Gas had $69 million of cash and cash equivalents. Committed credit arrangements with banks at June 30, 2018 were as follows:

Company	Expires 2022		Unused
	(in millions)
Southern Company Gas Capital(a)	$	1,400	$	1,395
Nicor Gas	500		500
Total(b)	$	1,900	$	1,895

(a) Southern Company Gas guarantees the obligations of Southern Company Gas Capital.

(b) Pursuant to the credit arrangement, the allocations between Southern Company Gas Capital and Nicor Gas may be adjusted.

See Note 6 to the consolidated financial statements of Southern Company Gas under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.

The multi-year credit arrangement of Southern Company Gas Capital and Nicor Gas (Facility) contains a covenant that limits the ratio of debt to capitalization (as defined in the Facility) to a maximum of 70% for each of Southern Company Gas and Nicor Gas and contains a cross-acceleration provision to other indebtedness (including guarantee obligations) of the applicable company. Such cross-acceleration provision to other indebtedness would trigger an event of default of the applicable company if Southern Company Gas or Nicor Gas defaulted on indebtedness, the payment of which was then accelerated. At June 30, 2018, both companies were in compliance with such covenant. The Facility does not contain a material adverse change clause at the time of borrowings.

Subject to applicable market conditions, the applicable company expects to renew or replace the Facility as needed, prior to expiration. In connection therewith, the applicable company may extend the maturity dates and/or increase or decrease the lending commitments thereunder. A portion of unused credit with banks provides liquidity support to Southern Company Gas.

Southern Company Gas makes short-term borrowings primarily through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above. Commercial paper borrowings are included in notes payable in the balance sheets.

Details of short-term borrowings were as follows:

	Short-Term Debt at June 30, 2018				Short-Term Debt During the Period(a)
	Amount Outstanding		Weighted Average Interest Rate		Average Amount Outstanding		Weighted Average Interest Rate		Maximum Amount Outstanding
Commercial paper:	(in millions)				(in millions)				(in millions)
Southern Company Gas Capital	$	573	2.4	%	$	709	2.4	%	$	855
Nicor Gas	154		2.3	%	104		2.2	%	180
Short-term loans:
Southern Company Gas(b)	276		2.8	%	111		2.7	%	276
Total	$	1,003	2.5	%	$	924	2.4	%

(a) Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 2018.

(b) Subsequent to June 30, 2018, Southern Company Gas repaid all $276 million of short-term loans.

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

Additionally, Pivotal Utility Holdings redeemed five series of gas facility revenue bonds issued under loan agreements with the New Jersey Economic Development Authority and Brevard County, Florida totaling $200 million during the second quarter 2018. See "Financing Activities" herein for additional information regarding the redemption of these bonds.

Credit Rating Risk

Southern Company Gas 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 below BBB- and/or Baa3. These contracts are for physical gas purchases and sales and energy price risk management. The maximum potential collateral requirement under these contracts at June 30, 2018 was approximately $10 million.

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 Gas to access capital markets and would be likely to impact the cost at which it does so.

As a result of the Tax Reform Legislation, certain financial metrics, such as the funds from operations to debt percentage, used by the credit rating agencies to assess Southern Company and its subsidiaries, including Southern Company Gas, may be negatively impacted. Southern Company Gas and certain of its subsidiaries are taking actions to mitigate the resulting impacts, which, among other alternatives, include adjusting capital structure. Absent actions by Southern Company and its subsidiaries that fully mitigate the impacts, Southern Company Gas', Southern Company Gas Capital's, and Nicor Gas' credit ratings could be negatively affected. The Georgia PSC's May 15, 2018 approval of a stipulation for Atlanta Gas Light's annual rate adjustment maintained the previously authorized earnings band and increased the equity ratio to address the negative cash flow and credit metric impacts of the Tax Reform Legislation. See Note 3 to the financial statements of Southern Company Gas under "Regulatory Matters" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory Matters – Southern Company Gas" herein for additional information.

Financing Activities

The long-term debt on Southern Company Gas' balance sheets includes both principal and non-principal components. As of June 30, 2018, the non-principal components totaled $483 million, which consisted of the unamortized portions of the fair value adjustment recorded in purchase accounting, debt premiums, debt discounts, and debt issuance costs.

On January 4, 2018, Southern Company Gas issued a floating rate promissory note to Southern Company in an aggregate principal amount of $100 million bearing interest based on one-month LIBOR. On March 28, 2018, Southern Company Gas repaid this promissory note.

In the second quarter 2018, Pivotal Utility Holdings caused $200 million aggregate principal amount of gas facility revenue bonds to be redeemed. Also in the second quarter 2018, Pivotal Utility Holdings, as borrower, and Southern Company Gas, as guarantor, entered into a $181 million short-term delayed draw floating rate bank term loan bearing interest based on one-month LIBOR, which Pivotal Utility Holdings used to repay the gas facility revenue bonds. Subsequent to June 30, 2018, Pivotal Utility Holdings repaid this short-term loan.

In May 2018, Southern Company Gas Capital borrowed $95 million pursuant to a short-term uncommitted bank credit arrangement, guaranteed by Southern Company Gas, bearing interest at a rate agreed upon by Southern Company Gas Capital and the bank from time to time and payable on no less than 30 days' demand by the bank. The proceeds of the loan were used to pay down short-term debt. Subsequent to June 30, 2018, Southern Company Gas Capital repaid this loan.

184

SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Subsequent to June 30, 2018, Nicor Gas agreed to issue $300 million aggregate principal amount of first mortgage bonds in a private placement, $100 million of which is expected to be issued in August 2018 and $200 million of which is expected to be issued in November 2018.

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

Market Price Risk

Other than the items discussed below, there were no material changes to Southern Company Gas' disclosures about market price risk during the second quarter2018. For an in-depth discussion of Southern Company Gas' market price risks, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of Southern Company Gas in Item 7 of the Form 10-K. Also see Notes (D) and (I) to the Condensed Financial Statements herein for information relating to derivative instruments.

Southern Company Gas is exposed to market risks, primarily commodity price risk, interest rate risk, and weather risk. Due to various cost recovery mechanisms, the natural gas distribution utilities of Southern Company Gas that sell natural gas directly to end-use customers have limited exposure to market volatility of natural gas prices. Certain natural gas distribution utilities of Southern Company Gas manage fuel-hedging programs implemented per the guidelines of their respective state regulatory agencies to hedge the impact of market fluctuations in natural gas prices for customers. For the weather risk associated with Nicor Gas, Southern Company Gas has a corporate weather hedging program that utilizes weather derivatives to reduce the risk of lower operating margins potentially resulting from significantly warmer-than-normal weather. In addition, certain non-regulated operations routinely utilize various types of derivative instruments to economically hedge certain commodity price and weather risks inherent in the natural gas industry. These instruments include a variety of exchange-traded and over-the-counter energy contracts, such as forward contracts, futures contracts, options contracts, and swap agreements. Some of these economic hedge activities may not qualify, or are not designated, for hedge accounting treatment. For the periods presented below, the changes in net fair value of Southern Company Gas' derivative contracts were as follows:

	Second Quarter 2018			Second Quarter 2017			Year-to-Date 2018			Year-to-Date 2017
	(in millions)
Contracts outstanding at beginning of period, assets (liabilities), net	$	(70	)	$	64		$	(106	)	$	12
Contracts realized or otherwise settled	2			(20		)	51			(16		)
Current period changes(a)	(22		)	7			(35		)	55
Contracts outstanding at the end of period, assets (liabilities), net	$	(90	)	$	51		$	(90	)	$	51
Netting of cash collateral	183			71			183			71
Cash collateral and net fair value of contracts outstanding at end of period(b)	$	93		$	122		$	93		$	122

(a) Current period changes also include the fair value of new contracts entered into during the period, if any.

(b) Net fair value of derivative contracts outstanding excludes premium and the intrinsic value associated with weather derivatives of $3 million at June 30, 2018 and includes premium and the intrinsic value associated with weather derivatives of $11 million at June 30, 2017.

185

SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The maturities of Southern Company Gas' energy-related derivative contracts at June 30, 2018 were as follows:

				Fair Value Measurements
				June 30, 2018
	Total Fair Value			Maturity
				Year 1			Years 2 & 3			Years 4 and thereafter
	(in millions)
Level 1(a)	$	(135	)	$	(24	)	$	(77	)	$	(34	)
Level 2(b)	45			13			33			(1		)
Fair value of contracts outstanding at end of period(c)	$	(90	)	$	(11	)	$	(44	)	$	(35	)

(a) Valued using NYMEX futures prices.

(b) Valued using basis transactions that represent the cost to transport natural gas from a NYMEX delivery point to the contract delivery point. These transactions are based on quotes obtained either through electronic trading platforms or directly from brokers.

(c) Excludes cash collateral of $183 million as well as premium and associated intrinsic value associated with weather derivatives of $3 million at June 30, 2018.

186

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

SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES

(UNAUDITED)

INDEX TO THE NOTES TO THE CONDENSED FINANCIAL STATEMENTS

Note		Page Number
A	Introduction	188
B	Contingencies and Regulatory Matters	198
C	Revenue from Contracts with Customers	215
D	Fair Value Measurements	221
E	Stockholders' Equity	225
F	Financing	227
G	Retirement Benefits	230
H	Income Taxes	235
I	Derivatives	237
J	Acquisitions and Dispositions	252
K	Variable Interest Entity and Equity Method Investments	257
L	Segment and Related Information	258

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, K, L
Alabama Power	A, B, C, D, F, G, H, I
Georgia Power	A, B, C, D, F, G, H, I
Gulf Power	A, B, C, D, F, G, H, I, J
Mississippi Power	A, B, C, D, F, G, H, I
Southern Power	A, B, C, D, E, F, G, H, I, J, K
Southern Company Gas	A, B, C, D, F, G, H, I, J, K, L

187

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

ALABAMA POWER COMPANY

GEORGIA POWER COMPANY

GULF POWER COMPANY

MISSISSIPPI POWER COMPANY

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES

SOUTHERN COMPANY GAS 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, 2017 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, 2018 and 2017. 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 Adopted Accounting Standards

See Note 1 to the financial statements of the registrants under "Recently Issued Accounting Standards" in Item 8 of the Form 10-K for additional information.

Revenue

In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry-specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. ASC 606 became effective on January 1, 2018 and the registrants adopted it using the modified retrospective method applied to open contracts and only to the version of the contracts in effect as of January 1, 2018. In accordance with the modified retrospective method, the registrants' previously issued financial statements have not been restated to comply with ASC 606 and the registrants did not have a cumulative-effect adjustment to retained earnings. The adoption of ASC 606 had no significant impact on the timing of revenue recognition compared to previously reported results; however, it requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers, which are included in Note (C).

188

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

ASC 606 provided additional clarity on financial statement presentation that resulted in reclassifications into other revenues and other operations and maintenance from other income/(expense), net at Alabama Power and Georgia Power related to certain unregulated sales of products and services. In addition, contract assets related to Southern Company's unregulated distributed generation business have been reclassified from unbilled revenue in accordance with the guidance in ASC 606. These reclassifications did not affect the timing or amount of revenues recognized or cash flows. ASC 606 also provided additional guidance on over-time revenue recognition, resulting in a change in the timing of revenue recognized from guaranteed and fixed billing arrangements at Southern Company Gas. The changes in natural gas revenues recognized in the second quarter and year-to-date 2018 relate primarily to the seasonal nature of natural gas usage.

The net impact of accounting for revenue under ASC 606 decreased Southern Company's consolidated net income by $5 million for the three months ended June 30, 2018 and increased Southern Company's consolidated net income by $5 million for the six months ended June 30, 2018.

The specific impacts of applying ASC 606 to revenues from contracts with customers on the financial statements of Southern Company, Alabama Power, Georgia Power, and Southern Company Gas compared to previously recognized guidance is shown below.

189

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

	For the Three Months Ended June 30, 2018									For the Six Months Ended June 30, 2018
Condensed Statements of Income	As Reported			Balances Without Adoption of ASC 606			Effect of Change			As Reported			Balances Without Adoption of ASC 606			Effect of Change
	(in millions)									(in millions)
Southern Company
Natural gas revenues	$	706		$	713		$	(7	)	$	2,314		$	2,307		$	7
Other revenues	395			393			2			808			805			3
Other operations and maintenance	1,559			1,546			13			3,008			2,985			23
Operating income	63			81			(18		)	1,439			1,452			(13		)
Other income (expense), net	78			67			11			138			118			20
Earnings (loss) before income taxes	(266		)	(259		)	(7		)	784			777			7
Income taxes (benefit)	(139		)	(137		)	(2		)	(25		)	(27		)	2
Consolidated net income (loss)	(127		)	(122		)	(5		)	809			804			5
Consolidated net income (loss) attributable to Southern Company	(154		)	(149		)	(5		)	784			779			5
Alabama Power
Other revenues	$	69		$	60		$	9		$	131		$	114		$	17
Other operations and maintenance	402			391			11			788			767			21
Operating income	380			382			(2		)	752			756			(4		)
Other income (expense), net	12			10			2			15			11			4
Georgia Power
Other revenues	$	120		$	97		$	23		$	227		$	189		$	38
Other operations and maintenance	457			437			20			863			828			35
Operating income (loss)	(472		)	(475		)	3			41			38			3
Other income (expense), net	35			38			(3		)	73			76			(3		)
Southern Company Gas
Natural gas revenues	$	710		$	717		$	(7	)	$	2,341		$	2,334		$	7
Operating income	49			56			(7		)	436			429			7
Earnings before income taxes	24			31			(7		)	407			400			7
Income taxes	55			57			(2		)	159			157			2
Net income (loss)	(31		)	(26		)	(5		)	248			243			5

190

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

	For the Six Months Ended June 30, 2018
Condensed Statements of Cash Flows	As Reported			Balances Without Adoption of ASC 606			Effect of Change
	(in millions)
Southern Company
Consolidated net income	$	809		$	804		$	5
Changes in certain current assets and liabilities:
Receivables	94			99			(5		)
Other current assets	(40		)	(45		)	5
Accrued taxes	213			215			(2		)
Other current liabilities	125			118			7
Georgia Power
Changes in certain current assets and liabilities:
Receivables	$	(103	)	$	(75	)	$	(28	)
Other current assets	25			(3		)	28
Southern Company Gas
Net income	$	248		$	243		$	5
Changes in certain current assets and liabilities:
Accrued taxes	38			40			(2		)
Other current liabilities	24			17			7

	At June 30, 2018
Condensed Balance Sheets	As Reported			Balances Without Adoption of ASC 606			Effect of Change
	(in millions)
Southern Company
Unbilled revenues	$	769		$	824		$	(55	)
Other accounts and notes receivable	621			622			(1		)
Other current assets	172			116			56
Accrued taxes	544			542			2
Other current liabilities	808			815			(7		)
Retained earnings	8,494			8,489			5
Southern Company Gas
Accrued income taxes	$	86		$	84		$	2
Other current liabilities	143			150			(7		)
Accumulated deficit	(202		)	(207		)	5

Other

In 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (ASU 2016-18). ASU 2016-18 eliminates the need to reflect transfers between cash and restricted cash in operating, investing, and financing activities in the statements of cash flows. In addition, the net change in cash and cash

191

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

equivalents during the period includes amounts generally described as restricted cash or restricted cash equivalents. The registrants adopted ASU 2016-18 effective January 1, 2018 with no material impact on their financial statements. Southern Company, Southern Power, and Southern Company Gas retrospectively applied ASU 2016-18 effective January 1, 2018 and have restated prior periods in the statements of cash flows by immaterial amounts. The change in restricted cash in the statements of cash flows was previously disclosed in operating activities for Southern Company and Southern Company Gas and in investing activities for Southern Company and Southern Power. See "Restricted Cash" herein for additional information.

In March 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in the statements of income outside of income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. The registrants adopted ASU 2017-07 effective January 1, 2018 with no material impact on their financial statements. ASU 2017-07 has been applied retrospectively for the presentation of the service cost component and the other components of net periodic benefit costs in the statements of income for Southern Company, the traditional electric operating companies, and Southern Company Gas. Since Southern Power did not participate in the qualified pension and postretirement benefit plans until December 2017, no retrospective presentation of Southern Power's net periodic benefits costs is required. The requirement to limit capitalization to the service cost component of net periodic benefit costs has been applied on a prospective basis from the date of adoption for all registrants. The presentation changes resulted in a decrease in operating income and an increase in other income for the three and six months ended June 30, 2018 and 2017 for Southern Company, the traditional electric operating companies, and Southern Company Gas.

In August 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12). ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The registrants adopted ASU 2017-12 effective January 1, 2018 with no material impact on their financial statements. See Note (I) for disclosures required by ASU 2017-12.

On February 14, 2018, the FASB issued ASU No. 2018-02, Income Statement – Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income (ASU 2018-02) to address the application of ASC 740, Income Taxes (ASC 740) to certain provisions of the Tax Reform Legislation. ASU 2018-02 specifically addresses the ASC 740 requirement that the effect of a change in tax laws or rates on deferred tax assets and liabilities be included in income from continuing operations, even when the tax effects were initially recognized directly in OCI at the previous rate, which strands the income tax rate differential in accumulated OCI. The amendments in ASU 2018-02 allow a reclassification from accumulated OCI to retained earnings for stranded tax effects resulting from the Tax Reform Legislation. The registrants adopted ASU 2018-02 effective January 1, 2018 with no material impact on their financial statements.

Asset Retirement Obligations

See Note 1 to the financial statements of Southern Company and the traditional electric operating companies under "Asset Retirement Obligations and Other Costs of Removal" in Item 8 of the Form 10-K for additional information regarding each company's AROs and the EPA's Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule).

192

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

As of June 30, 2018, details of the AROs, including those related to the CCR Rule, included in the condensed balance sheets of Southern Company, Alabama Power, and Mississippi Power were as follows:

	Southern Company			Alabama Power			Mississippi Power
	(in millions)
Balance at December 31, 2017	$	4,824		$	1,709		$	174
Liabilities incurred	1			—			—
Liabilities settled	(97		)	(19		)	(15		)
Accretion	95			41			2
Cash flow revisions	1,493			1,451			15
Reclassification to held for sale	(148		)	—			—
Balance at June 30, 2018	$	6,168		$	3,182		$	176

In June 2018, Alabama Power recorded an increase of approximately $1.2 billion to its AROs related to the CCR Rule. The revised cost estimates as of June 30, 2018 are based on information from feasibility studies performed on ash ponds in use at plants operated by Alabama Power, including a plant jointly-owned by Mississippi Power. During the second quarter 2018, Alabama Power's management completed its analysis of these studies which indicated that additional closure costs, primarily related to increases in estimated ash volume, water management requirements, and design revisions, will be required to close these ash ponds under the planned closure-in-place methodology. As a result of these revised cost estimates, in June 2018, Mississippi Power recorded an increase of approximately $11 million to its AROs related to an ash pond at the plant jointly-owned with Alabama Power.

Georgia Power continues to perform engineering studies related to its plans to close the ash ponds at all of its generating plants, including one jointly owned with Gulf Power, in compliance with federal and state CCR rules. Georgia Power also continues to refine its closure strategy and cost estimates for each ash pond and is preparing permit applications as required by the State of Georgia CCR rule. While each of Georgia Power and Gulf Power believes its recorded liability for ash pond closures appropriately reflects its obligations under the current closure strategies it has elected, changes to such strategies and cost estimates would likely result in additional closure costs which would increase each of Georgia Power's and Gulf Power's ARO liability. It is not currently possible to determine the magnitude of an increase related to a change in closure strategies nor an increase related to ongoing engineering studies for the current closure strategies, and the timing of future cash outflows are indeterminable at this time. As permit applications advance, engineering studies continue, and the timing of ash pond closures develop further on a plant-by-plant basis during the second half of 2018 and in the future, Georgia Power will record any changes as necessary to its ARO liability, which could be material. Georgia Power expects to continue to periodically update these cost estimates as necessary, which could change further as additional information becomes available. Gulf Power will record any incremental AROs, which could be material, related to its share of Plant Scherer Unit 3, which is co-owned with Georgia Power, once Georgia Power further refines its cost estimate of the impact on its ARO liability.

As further analysis is performed and closure details are developed with respect to ash pond closures, the traditional electric operating companies expect to periodically update their cost estimates as necessary. Absent continued recovery of ARO costs through regulated rates, Southern Company's and the traditional electric operating companies' results of operations, cash flows, and financial condition could be materially impacted. The ultimate outcome of this matter cannot be determined at this time.

In June 2018, Alabama Power completed an updated decommissioning cost site study for Plant Farley. The estimated cost of decommissioning based on the study resulted in an increase in Southern Company's and Alabama Power's ARO liability of approximately $300 million. See "Nuclear Decommissioning" below for additional information.

193

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

The reclassification of a portion of the ARO liability to liabilities held for sale by Southern Company represents the AROs related to Gulf Power. See Note (J) under "Southern Company's Sale of Gulf Power" and "Assets Held for Sale" for additional information.

Nuclear Decommissioning

See Note 1 to the financial statements of Southern Company and Alabama Power under "Nuclear Decommissioning" in Item 8 of the Form 10-K for additional information.

In June 2018, Alabama Power completed an updated decommissioning cost site study for Plant Farley. The estimated costs of decommissioning based on the 2018 site study are as follows:

Decommissioning periods:
Beginning year	2037
Completion year	2076
	(in millions)
Site study costs:
Radiated structures	$	1,621
Non-radiated structures	99
Total site study costs	$	1,720

The decommissioning cost estimates are based on prompt dismantlement and removal of the plant from service. The actual decommissioning costs may vary from the above estimates because of changes in the assumed date of decommissioning, changes in NRC requirements, or changes in the assumptions used in making these estimates.

For ratemaking purposes, Alabama Power's decommissioning costs are based on the site study. Significant assumptions used to determine these costs for ratemaking were an inflation rate of 4.5% and a trust earnings rate of 7.0%. The next site study is expected to be completed in 2023.

Amounts previously contributed to the external trust funds are currently projected to be adequate to meet the updated decommissioning obligations. Alabama Power will continue to provide site specific estimates of the decommissioning costs and related projections of funds in the external trust to the Alabama PSC and, if necessary, would seek the Alabama PSC's approval to address any changes in a manner consistent with the NRC and other applicable requirements.

194

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Goodwill and Other Intangible Assets

The following table presents year-to-date changes in goodwill balances for Southern Company and Southern Company Gas:

	Goodwill
	Southern Company				Southern Company Gas
					Gas Distribution Operations			Gas Marketing Services			Total
	(in millions)
Balance at December 31, 2017	$	6,268			$	4,702		$	1,265		$	5,967
Impairment(a)	(42		)		—			(42		)	(42		)
Sale of Pivotal Home Solutions(a)	(242		)		—			(242		)	(242		)
Reclassification to held for sale(b)	(668		)		(668		)	—			(668		)
Balance at June 30, 2018	$	5,315		(c)	$	4,034		$	981		$	5,015

(a) On April 11, 2018, Southern Company Gas entered into a stock purchase agreement for the sale of Pivotal Home Solutions. In contemplation of the transaction, a goodwill impairment charge of $42 million was recorded in the first quarter 2018. On June 4, 2018, Southern Company Gas and Pivotal Home Solutions completed this transaction. See Note (J) under "Southern Company Gas" for additional information.

(b) Reflects goodwill associated with Elizabethtown Gas, Elkton Gas, and Florida City Gas, which were sold subsequent to June 30, 2018. See Note (J) under "Southern Company Gas" and "Assets Held for Sale" for additional information.

(c) Total does not add due to rounding.

Goodwill is not amortized but is subject to an annual impairment test during the fourth quarter of each year or more frequently if impairment indicators arise.

195

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Other intangible assets were as follows:

	At June 30, 2018							At December 31, 2017
	Gross Carrying Amount		Accumulated Amortization			Other Intangible Assets, Net		Gross Carrying Amount		Accumulated Amortization			Other Intangible Assets, Net
	(in millions)							(in millions)
Southern Company
Other intangible assets subject to amortization:
Customer relationships(*)	$	223	$	(79	)	$	144	$	288	$	(83	)	$	205
Trade names(*)	70		(17		)	53		159		(17		)	142
Storage and transportation contracts	64		(44		)	20		64		(34		)	30
PPA fair value adjustments	456		(60		)	396		456		(47		)	409
Other	19		(5		)	14		17		(5		)	12
Total other intangible assets subject to amortization	$	832	$	(205	)	$	627	$	984	$	(186	)	$	798
Other intangible assets not subject to amortization:
Federal Communications Commission licenses	75		—			75		75		—			75
Total other intangible assets	$	907	$	(205	)	$	702	$	1,059	$	(186	)	$	873
Southern Power
Other intangible assets subject to amortization:
PPA fair value adjustments	$	456	$	(60	)	$	396	$	456	$	(47	)	$	409
Southern Company Gas
Other intangible assets subject to amortization:
Gas marketing services(*)
Customer relationships	$	156	$	(71	)	$	85	$	221	$	(77	)	$	144
Trade names	26		(6		)	20		115		(9		)	106
Wholesale gas services
Storage and transportation contracts	64		(44		)	20		64		(34		)	30
Total other intangible assets subject to amortization	$	246	$	(121	)	$	125	$	400	$	(120	)	$	280

(*) Balances as of June 30, 2018 reflect Southern Company Gas' sale of Pivotal Home Solutions. See Note (J) under "Southern Company Gas – Sale of Pivotal Home Solutions" for additional information.

196

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Amortization associated with other intangible assets was as follows:

	Three Months Ended		Six Months Ended
	June 30, 2018
	(in millions)
Southern Company	$	23	$	50
Southern Power	$	6	$	13
Southern Company Gas	$	14	$	31

Restricted Cash

The registrants adopted ASU 2016-18 as of January 1, 2018. See "Recently Adopted Accounting Standards – Other" herein for additional information.

At December 31, 2017, Southern Power had restricted cash primarily related to certain acquisitions and construction projects. At both June 30, 2018 and December 31, 2017, Southern Company Gas had restricted cash held as collateral for worker's compensation, life insurance, and long-term disability insurance.

The following tables provide a reconciliation of cash, cash equivalents, and restricted cash reported within the condensed balance sheets that total to the amounts shown in the condensed statements of cash flows for the registrants that had restricted cash at June 30, 2018 and/or December 31, 2017:

	Southern Company		Southern Company Gas
	(in millions)
At June 30, 2018
Cash and cash equivalents	$	1,980	$	69
Cash and cash equivalents classified as assets held for sale	31		—
Restricted cash:
Other accounts and notes receivable	6		6
Total cash, cash equivalents, and restricted cash	$	2,017	$	75

	Southern Company		Southern Power		Southern Company Gas
	(in millions)
At December 31, 2017
Cash and cash equivalents	$	2,130	$	129	$	73
Restricted cash:
Other accounts and notes receivable	5		—		5
Deferred charges and other assets	12		11		—
Total cash, cash equivalents, and restricted cash	$	2,147	$	140	$	78

Natural Gas for Sale

Southern Company Gas' natural gas distribution utilities, with the exception of Nicor Gas, carry natural gas inventory on a WACOG basis.

Nicor Gas' natural gas inventory is carried at cost on a LIFO basis. Inventory decrements occurring during the year that are restored prior to year end are charged to cost of natural gas at the estimated annual replacement cost. Inventory decrements that are not restored prior to year end are charged to cost of natural gas at the actual LIFO

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cost of the inventory layers liquidated. Southern Company Gas' inventory decrement at June 30, 2018 is expected to be restored prior to year end. The cost of natural gas, including inventory costs, is recovered from customers under a purchased gas recovery mechanism adjusted for differences between actual costs and amounts billed; therefore, LIFO liquidations have no impact on Southern Company's or Southern Company Gas' net income.

Natural gas inventories for Southern Company Gas' non-utility businesses are carried at the lower of weighted average cost or current market price, with cost determined on a WACOG basis. For any declines in market prices below the WACOG considered to be other than temporary, an adjustment is recorded to reduce the value of natural gas inventories to market value. Southern Company Gas had no material LOCOM adjustment in any period presented.

Hypothetical Liquidation at Book Value

Southern Power has consolidated renewable generation projects that are partially funded by a third-party tax equity investor. The related contractual provisions represent profit-sharing arrangements because the allocations of cash distributions and tax benefits are not based on fixed ownership percentages. Therefore, the noncontrolling interest is accounted for under a balance sheet approach utilizing the hypothetical liquidation at book value (HLBV) method. The HLBV method calculates each partner's share of income based on the change in net equity the partner can legally claim in a hypothetical liquidation at the end of the period compared to the beginning of the period.

(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, the business activities of Southern Company's subsidiaries are subject to extensive governmental regulation related to public health and the environment, such as laws and regulations governing air, water, land, and protection of natural resources. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental laws and regulations has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO₂ and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.

The ultimate outcome of such pending or potential litigation against each registrant and any subsidiaries cannot be predicted at this time; however, for current proceedings not specifically reported herein, 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.

Southern Company

In January 2017, a putative securities class action complaint was filed against Southern Company, certain of its officers, and certain former Mississippi Power officers in the U.S. District Court for the Northern District of Georgia, Atlanta Division, by Monroe County Employees' Retirement System on behalf of all persons who purchased shares of Southern Company's common stock between April 25, 2012 and October 29, 2013. The complaint alleges that Southern Company, certain of its officers, and certain former Mississippi Power officers made materially false and misleading statements regarding the Kemper County energy facility in violation of certain provisions under the Securities Exchange Act of 1934, as amended. The complaint seeks, among other things, compensatory damages and litigation costs and attorneys' fees. In June 2017, the plaintiffs filed an amended complaint that provided additional detail about their claims, increased the purported class period by one day, and added certain other former Mississippi Power officers as defendants. In July 2017, the defendants filed a motion to dismiss the plaintiffs' amended complaint with prejudice, to which the plaintiffs filed an opposition in September 2017. On March 29, 2018, the U.S. District Court for the Northern District of Georgia, Atlanta Division, issued an

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order granting, in part, the defendants' motion to dismiss. The court dismissed certain claims against certain officers of Southern Company and Mississippi Power and dismissed the allegations related to a number of the statements that plaintiffs challenged as being false or misleading. On April 26, 2018, the defendants filed a motion for reconsideration of the court's order, seeking dismissal of the remaining claims in the lawsuit.

In February 2017, Jean Vineyard filed a shareholder derivative lawsuit and, in May 2017, Judy Mesirov filed a shareholder derivative lawsuit, each in the U.S. District Court for the Northern District of Georgia. Each of these lawsuits names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. In August 2017, these two shareholder derivative lawsuits were consolidated in the U.S. District Court for the Northern District of Georgia. The complaints allege that the defendants caused Southern Company to make false or misleading statements regarding the Kemper County energy facility cost and schedule. Further, the complaints allege that the defendants were unjustly enriched and caused the waste of corporate assets and also allege that the individual defendants violated their fiduciary duties. Each plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and, on each plaintiff's own behalf, attorneys' fees and costs in bringing the lawsuit. Each plaintiff also seeks certain changes to Southern Company's corporate governance and internal processes. On April 25, 2018, the court entered an order staying this lawsuit until 30 days after the resolution of any dispositive motions or any settlement, whichever is earlier, in the putative securities class action.

In May 2017, Helen E. Piper Survivor's Trust filed a shareholder derivative lawsuit in the Superior Court of Gwinnett County, State of Georgia that names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. The complaint alleges that the individual defendants, among other things, breached their fiduciary duties in connection with schedule delays and cost overruns associated with the construction of the Kemper County energy facility. The complaint further alleges that the individual defendants authorized or failed to correct false and misleading statements regarding the Kemper County energy facility schedule and cost and failed to implement necessary internal controls to prevent harm to Southern Company. The plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and disgorgement of profits and, on its behalf, attorneys' fees and costs in bringing the lawsuit. The plaintiff also seeks certain unspecified changes to Southern Company's corporate governance and internal processes. The court entered an order staying this lawsuit until 30 days after the resolution of any dispositive motions or any settlement, whichever is earlier, in the putative securities class action.

Southern Company believes these legal challenges have no merit; however, an adverse outcome in any of 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, the ultimate outcome of which cannot be determined at this time.

Alabama Power

On March 2, 2018, the Alabama Department of Environmental Management (ADEM) issued proposed administrative orders assessing a penalty of $1.25 million to Alabama Power for unpermitted discharge of fluids and/or pollutants to groundwater at five electric generating plants. The proposed orders also require the submission to the ADEM of a plan with a schedule for implementation of a comprehensive groundwater investigation, including an assessment of corrective measures, a report evaluating any deficiencies at the facilities that may have led to the unpermitted discharges, and quarterly progress reports. Alabama Power is awaiting finalization of the orders. The ultimate outcome of this matter cannot be determined at this time.

Georgia Power

In 2011, plaintiffs filed a putative class action against Georgia Power in the Superior Court of Fulton County, Georgia alleging that Georgia Power's collection in rates of municipal franchise fees (all of which are remitted to municipalities) exceeded the amounts allowed in orders of the Georgia PSC and alleging certain state tort law claims. In 2016, the Georgia Court of Appeals reversed the trial court's previous dismissal of the case and remanded the case to the trial court. Georgia Power filed a petition for writ of certiorari with the Georgia Supreme Court, which was granted in August 2017. On June 18, 2018, the Georgia Supreme Court affirmed the judgment of the

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Georgia Court of Appeals and the case has been remanded to the trial court for further proceedings. Georgia Power believes the plaintiffs' claims have no merit and intends to vigorously defend itself in this matter. The amount of any possible losses cannot be calculated at this time because, among other factors, it is unknown whether any class will ultimately be certified; the scope of such a class, if certified; and whether any losses would be subject to recovery from any municipalities. The ultimate outcome of this matter cannot be determined at this time.

Mississippi Power

In 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 to include, among other things, Southern Company as a defendant. The individual plaintiff alleged that Mississippi Power and Southern Company violated the Mississippi Unfair Trade Practices Act. All plaintiffs 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 County energy facility and that these alleged breaches unjustly enriched Mississippi Power and Southern Company. The plaintiffs sought unspecified actual damages and punitive damages; asked the Circuit Court to appoint a receiver to oversee, operate, manage, and otherwise control all affairs relating to the Kemper County energy facility; asked the Circuit Court to revoke any licenses or certificates authorizing Mississippi Power or Southern Company to engage in any business related to the Kemper County energy facility in Mississippi; and sought attorney's fees, costs, and interest. The plaintiffs also sought an injunction to prevent any Kemper County energy facility costs from being charged to customers through electric rates. In June 2017, the Circuit Court ruled in favor of motions by Southern Company and Mississippi Power and dismissed the case. In July 2017, the plaintiffs filed notice of an appeal. On July 13, 2018, Mississippi Power and Southern Company reached a settlement agreement with the plaintiffs and the plaintiffs' appeal was dismissed with prejudice. The settlement had no material impact on Southern Company's or Mississippi Power's financial statements.

On May 18, 2018, Southern Company and Mississippi Power received a notice of dispute and arbitration demand filed by Martin Product Sales, LLC (Martin) based on two agreements, both related to Kemper IGCC byproducts for which Mississippi Power provided termination notices in September 2017. Martin alleges breach of contract, breach of good faith and fair dealing, fraud and misrepresentation, and civil conspiracy and makes a claim for damages in the amount of approximately $143 million, as well as additional unspecified damages, attorney's fees, costs, and interest. Southern Company and Mississippi Power believe this legal challenge has no merit; however, an adverse outcome in this proceeding could have a material impact on Southern Company's and Mississippi Power's results of operations, financial condition, and liquidity. Southern Company and Mississippi Power will vigorously defend themselves in this matter, the ultimate outcome of which cannot be determined at this time.

On May 14, 2018, Mississippi Power's claim for lost revenue resulting from the Deepwater Horizon oil spill in the Gulf of Mexico in 2010 was settled. The settlement proceeds of $18 million, net of expenses and income tax, are included in Southern Company's and Mississippi Power's earnings for the second quarter 2018.

Southern Power

Southern Power indirectly owns a 51% membership interest in RE Roserock LLC (Roserock), the owner of the Roserock facility in Pecos County, Texas. Prior to the facility being placed in service in November 2016, certain solar panels were damaged during installation by the construction contractor, McCarthy Building Companies, Inc. (McCarthy), and certain solar panels were damaged by a hail event that also occurred during construction. In May 2017, Roserock filed a lawsuit in the state district court in Pecos County, Texas, (State Court lawsuit) against XL Insurance America, Inc. (XL) and North American Elite Insurance Company (North American Elite) seeking recovery from an insurance policy for damages resulting from the hail storm and McCarthy's installation practices. On June 1, 2018, the court in the State Court lawsuit granted Roserock's motion for partial summary judgment, finding that the insurers were in breach of contract and in violation of the Texas Insurance Code for failing to pay any monies owed for the hail claim. Roserock is working to distinguish its damages between those attributable to the hail event versus damages attributable to installation. In addition to the State Court lawsuit, lawsuits were filed

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between Roserock and McCarthy, as well as other parties, and that litigation has been consolidated in the U.S. District Court for the Western District of Texas. Southern Power intends to vigorously pursue and defend these matters, the ultimate outcome of which cannot be determined at this time.

Southern Company Gas

Nicor Energy Services Company, doing business as Pivotal Home Solutions, formerly a wholly-owned subsidiary of Southern Company Gas, was a defendant in a putative class action initially filed in 2017 in the state court in Indiana. The plaintiffs purported to represent a class of the customers who purchased products from Nicor Energy Services Company and alleged that the marketing, sale, and billing of the products violated the Indiana Consumer Fraud and Deceptive Business Practices Act, constituting common law fraud and resulting in unjust enrichment of these entities. In 2018, Nicor Energy Services Company was named in a second class action filed in the state court of Ohio asserting nearly identical allegations and legal claims. The plaintiffs sought, on behalf of the classes they purported to represent, actual and punitive damages, interest costs, attorney fees, and injunctive relief. To facilitate the sale of Pivotal Home Solutions, Southern Company Gas retained most of the financial responsibility for these lawsuits following the completion of the sale. On June 12, 2018, the parties settled these claims and Southern Company Gas recorded an $11 million charge, which is reflected in other operations and maintenance expenses on the statements of income.

Environmental Matters

Environmental Remediation

The Southern Company system must comply with environmental laws and regulations governing 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 and the natural gas distribution utilities in Illinois, New Jersey, Georgia, and Florida have all received authority from their respective state PSCs or other applicable state regulatory agencies to recover approved environmental compliance costs through regulatory mechanisms. These regulatory mechanisms are adjusted annually or as necessary within limits approved by the state PSCs or other applicable state regulatory agencies.

Georgia Power's environmental remediation liability was $25 million and $22 million as of June 30, 2018 and December 31, 2017, respectively. Georgia Power has been designated or identified as a potentially responsible party at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act, and assessment and potential cleanup of such sites is expected.

Gulf Power's environmental remediation liability includes estimated costs of environmental remediation projects of approximately $48 million and $52 million as of June 30, 2018 and December 31, 2017, respectively. 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's substations. The schedule for completion of the remediation projects is subject to FDEP approval.

At June 30, 2018, Southern Company Gas' environmental remediation liability was $305 million based on the estimated cost of environmental investigation and remediation associated with known current and former manufactured gas plant operating sites, with an additional $77 million liability related to Elizabethtown Gas classified as held for sale. At December 31, 2017, Southern Company Gas' total environmental remediation liability was $388 million, of which $85 million related to Elizabethtown Gas. These environmental remediation expenditures are recoverable from customers through rate mechanisms approved by the applicable state regulatory agencies of the natural gas distribution utilities, with the exception of one site representing $2 million of the total accrued remediation costs. See Note (J) under "Southern Company Gas" and "Assets Held for Sale" for additional information.

The ultimate outcome of these matters cannot be determined at this time; however, as a result of the regulatory treatment for environmental remediation expenses described above, the final disposition of these matters is not

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expected to have a material impact on the financial statements of Southern Company, Georgia Power, Gulf Power, or Southern Company Gas.

FERC Matters

Market-Based Rate Authority

See Note 3 to the financial statements of Southern Company, the traditional electric operating companies, and Southern Power under "FERC Matters" in Item 8 of the Form 10-K for additional information regarding proceedings related to the traditional electric operating companies'and Southern Power's 2014 and 2017 triennial market power analyses.

On May 4, 2018, the FERC issued an order terminating both proceedings, finding that the traditional electric operating companiesand Southern Power satisfy the FERC's standards for market-based rates. On May 9, 2018, the traditional electric operating companiesand Southern Power made the compliance filing required by the order. These proceedings are essentially concluded.

Open Access Transmission Tariff

On May 10, 2018, the Alabama Municipal Electric Authority and Cooperative Energy filed with the FERC a complaint against SCS and the traditional electric operating companiesclaiming that the current11.25%base ROE used in calculating the annual transmission revenue requirements of the traditional electric operating companies'open access transmission tariff is unjust and unreasonable as measured by the applicable FERC standards. The complaint requests that the base ROE be set no higher than8.65%and that the FERC order refunds for the difference in revenue requirements that results from applying a just and reasonable ROE established in this proceeding upon determining the current ROE is unjust and unreasonable. On June 18, 2018, SCS and the traditional electric operating companiesfiled their response challenging the adequacy of the showing presented by the complainants and offering support for the current ROE. The ultimate outcome of this matter cannot be determined at this time.

Cooperative Energy Power Supply Agreement

See Note 3 to the financial statements of Mississippi Power under "FERC Matters – Cooperative Energy Power Supply Agreement" in Item 8 of the Form 10-K for additional information regarding Cooperative Energy's network integration transmission service agreement (NITSA) with SCS.

On March 23, 2018, the FERC accepted the amendment to the NITSA between Cooperative Energy and SCS, effective April 1, 2018.

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Regulatory Matters

Alabama Power

See Note 3 to the financial statements of Southern Company and Alabama Power under "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, 2018		December 31, 2017
		(in millions)
Rate CNP Compliance	Deferred under recovered regulatory clause revenues	$	30	$	17
Rate CNP PPA	Deferred under recovered regulatory clause revenues	11		12
Retail Energy Cost Recovery	Deferred under recovered regulatory clause revenues	80		25
	Under recovered regulatory clause revenues	28		—
Natural Disaster Reserve	Other regulatory liabilities, deferred	30		38

On May 1, 2018, the Alabama PSC approved modifications to Rate RSE and other commitments designed to position Alabama Power to address the growing pressure on its credit quality resulting from the Tax Reform Legislation, without increasing retail rates under Rate RSE in the near term. Alabama Power plans to reduce growth in total debt by increasing equity, with corresponding reductions in debt issuances, thereby de-leveraging its capital structure. Alabama Power's goal is to achieve an equity ratio of approximately 55% by the end of 2025. At June 30, 2018, Alabama Power's equity ratio was approximately 46.6%.

Rate RSE

The approved modifications to Rate RSE became effective June 2018 and are applicable for January 2019 billings and thereafter. The modifications include reducing the top of the allowed weighted common equity return (WCER) range from 6.21% to 6.15% and modifications to the refund mechanism applicable to prior year actual results. The modifications to the refund mechanism allow Alabama Power to retain a portion of the revenue that causes the actual WCER for a given year to exceed the allowed range.

Generally, if Alabama Power's actual WCER range is between 6.15% and 7.65%, customers will receive 25% of the amount between 6.15% and 6.65%, 40% of the amount between 6.65% and 7.15%, and 75% of the amount between 7.15% and 7.65%. Customers will receive all amounts in excess of an actual WCER of 7.65%.

In conjunction with these modifications to Rate RSE, on May 8, 2018, Alabama Power consented to a moratorium on any upward adjustments under Rate RSE for 2019 and 2020. Additionally, Alabama Power will return $50 million to customers through bill credits in 2019.

In accordance with an established retail tariff that provides for an interim adjustment to customer billings to recognize the impact of a change in the statutory income tax rate, Alabama Power is returning approximately $257 million to retail customers through bill credits in the second half of 2018 as a result of the change in the federal income tax rate under the Tax Reform Legislation.

Rate ECR

On May 1, 2018, the Alabama PSC approved an increase to Rate ECR from 2.015 cents per KWH to 2.353 cents per KWH effective July 2018 which is expected to result in additional collections of approximately $100 million through December 31, 2018. The approved increase in the Rate ECR factor will have no significant effect on

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Alabama Power's net income, but will increase operating cash flows related to fuel cost recovery in 2018. The rate will return to 5.910 cents per KWH in 2019, absent a further order from the Alabama PSC.

Accounting Order

On May 1, 2018, the Alabama PSC approved an accounting order that authorizes Alabama Power to defer the benefits of federal excess deferred income taxes associated with the Tax Reform Legislation for the year ending December 31, 2018 as a regulatory liability and to use up to $30 million of such deferrals to offset under recovered amounts under Rate ECR. Any remaining amounts will be used for the benefit of customers as determined by the Alabama PSC. As of June 30, 2018, Alabama Power had applied approximately $30 million of such deferrals to offset the under recovered balance under Rate ECR and expects the total deferrals for the year ending December 31, 2018 to be approximately $50 million. See Note 5 to the financial statements of Southern Company and Alabama Power under "Federal Tax Reform Legislation" and of Alabama Power under "Current and Deferred Income Taxes" in Item 8 of the Form 10-K for additional information.

Plant Greene County

Alabama Power jointly owns Plant Greene County with an affiliate, Mississippi Power. See Note 4 to the financial statements of Alabama Power in Item 8 of the Form 10-K for additional information regarding the joint ownership agreement. On August 6, 2018, Mississippi Power filed its proposed Reserve Margin Plan (RMP) with the Mississippi PSC, which proposes a 4-year acceleration of the retirement of Plant Greene County Units 1 and 2 to the third quarter 2021 and the third quarter 2022, respectively. Mississippi Power's proposed Plant Greene County unit retirements would require the completion of proposed transmission and system reliability improvements, as well as agreement by Alabama Power. Alabama Power will monitor Mississippi Power's proposed RMP and associated regulatory process as well as the proposed transmission and system reliability improvements. Alabama Power will review all the facts and circumstances and will evaluate all its alternatives prior to reaching a final determination on the ongoing operations of Plant Greene County. The ultimate outcome of this matter cannot be determined at this time.

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 certified construction costs of Plant Vogtle Units 3 and 4 are being collected through the NCCR tariff and fuel costs are collected through a separate fuel cost recovery tariff. See "Nuclear Construction" herein and Note 3 to the financial statements of Southern Company under "Nuclear Construction" and Georgia Power under "Retail Regulatory Matters – Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding the NCCR tariff. Also see "Fuel Cost Recovery" herein and Note 3 to the financial statements of Southern Company under "Regulatory Matters – Georgia Power – Fuel Cost Recovery" and Georgia Power under "Retail Regulatory Matters – Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information regarding fuel cost recovery.

Rate Plans

See Note 3 to the financial statements of Southern Company and Georgia Power under "Regulatory Matters – Georgia Power – Rate Plans" and "Retail Regulatory Matters – Rate Plans," respectively, in Item 8 of the Form 10-K for additional information regarding Georgia Power's 2013 ARP and the Georgia PSC's 2018 order related to the Tax Reform Legislation.

On April 3, 2018, the Georgia PSC approved a settlement agreement between Georgia Power and the staff of the Georgia PSC regarding the retail rate impact of the Tax Reform Legislation (Georgia Power Tax Reform Settlement Agreement). Pursuant to the Georgia Power Tax Reform Settlement Agreement, to reflect the federal income tax rate reduction impact of the Tax Reform Legislation, Georgia Power will refund to customers a total of $330 million through bill credits of $131 million in October 2018, $96 million in June 2019, and $103 million in February 2020.

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In addition, Georgia Power is deferring as a regulatory liability (i) the revenue equivalent of the tax expense reduction resulting from legislation lowering the Georgia state income tax rate from 6.00% to 5.75% in 2019 and (ii) the entire benefit of approximately $700 million in federal and state excess accumulated deferred income taxes. The amortization of these regulatory liabilities is expected to be addressed in Georgia Power's next base rate case, which is scheduled to be filed by July 1, 2019. If there is not a base rate case in 2019, customers will receive $185 million in annual bill credits beginning in 2020, with any additional federal and state income tax savings deferred as a regulatory liability, until Georgia Power's next base rate case.

To address the negative cash flow and credit metric impacts of the Tax Reform Legislation, the Georgia PSC also approved an increase in Georgia Power's retail equity ratio to the lower of (i) Georgia Power's actual common equity weight in its capital structure or (ii) 55%, until Georgia Power's next base rate case. Benefits from reduced federal income tax rates in excess of the amounts refunded to customers will be retained by Georgia Power to cover the carrying costs of the incremental equity in 2018 and 2019.

Fuel Cost Recovery

As of June 30, 2018 and December 31, 2017, Georgia Power's under recovered fuel balance totaled $159 million and $165 million, respectively, and is included as under recovered fuel clause revenues on Southern Company's and Georgia Power's condensed balance sheets. The Georgia PSC will review Georgia Power's cumulative over or under recovered fuel balance no later than September 1, 2018 and evaluate the need to file a fuel case. Georgia Power continues to be allowed to adjust its fuel cost recovery rates under an interim fuel rider prior to the next fuel case if the under or over recovered fuel balance exceeds $200 million.

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.

Gulf Power

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 regarding Gulf Power's rates and charges for service to retail customers.

Retail Base Rate Case

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

As a continuation of a settlement agreement approved by the Florida PSC in April 2017 (2017 Gulf Power Rate Case Settlement Agreement), on March 26, 2018, the Florida PSC approved a stipulation and settlement agreement among Gulf Power and three intervenors addressing the retail revenue requirement effects of the Tax Reform Legislation (Gulf Power Tax Reform Settlement Agreement).

The Gulf Power Tax Reform Settlement Agreement results in annual reductions to Gulf Power's revenues of $18.2 million from base rates and $15.6 million from environmental cost recovery rates, implemented April 1, 2018, and also provides for a one-time refund of $69.4 million for the retail portion of unprotected (not subject to normalization) deferred tax liabilities through a reduced fuel cost recovery rate over the remainder of 2018. Through June 30, 2018, approximately $28 million of this refund has been reflected in customer bills. As a result of the Gulf Power Tax Reform Settlement Agreement, the Florida PSC also approved an increase in Gulf Power's maximum equity ratio from 52.5% to 53.5% for all retail regulatory purposes.

As part of the Gulf Power Tax Reform Settlement Agreement, a limited scope proceeding to address protected deferred tax liabilities consistent with IRS normalization principles was initiated on April 30, 2018. Pending resolution of this proceeding, Gulf Power is deferring the related amounts for 2018 as a regulatory liability. Through June 30, 2018, amounts deferred totaled $5 million. Unless otherwise agreed to by the parties to the Gulf Power Tax Reform Settlement Agreement, amounts recorded in this regulatory liability will be refunded to retail customers in

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2019 through Gulf Power's fuel cost recovery rates. The ultimate outcome of this matter cannot be determined at this time.

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, as approved by the Florida PSC. Regulatory clause recovery balances included in the balance sheets are as follows:

Regulatory Clause	Balance Sheet Line Item	June 30, 2018		December 31, 2017
		(in millions)
Fuel Cost Recovery	Under recovered regulatory clause revenues	$	—	$	22
Fuel Cost Recovery	Other regulatory liabilities, current	5		—
Purchased Power Capacity Recovery	Under recovered regulatory clause revenues	2		2
Environmental Cost Recovery(*)	Under recovered regulatory clause revenues	1		2
Energy Conservation Cost Recovery	Other regulatory liabilities, current	1		—

(*) At June 30, 2018 and December 31, 2017, the under recovered balance included in the balance sheets represents the current portion of the regulatory assets associated with projected environmental expenditures of approximately $11 million and $13 million, respectively, partially offset by the over recovered environmental cost recovery balance of approximately $10 million and $11 million, respectively.

Mississippi Power

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

On May 8, 2018, the Mississippi PSC issued an order to begin an operations review of Mississippi Power in August 2018 with the final report expected by February 28, 2019. Mississippi Power expects that the review will include, but not be limited to, a comparative analysis of its costs, its cost recovery framework, and ways in which it may streamline management operations for the reasonable benefit of ratepayers. The ultimate outcome of this matter cannot be determined at this time.

Performance Evaluation Plan

In each of 2014, 2015, 2016, and 2017, Mississippi Power submitted its annual PEP lookback filing for the prior year, which for 2013 and 2014 each indicated no surcharge or refund and for each of 2015 and 2016 indicated a $5 million surcharge. Additionally, in July 2016, in November 2016, and on November 15, 2017, Mississippi Power submitted its annual projected PEP filings for 2016, 2017, and 2018, respectively, which for 2016 and 2017 indicated no change in rates and for 2018 indicated a rate increase of 4%, or $38 million in annual revenues. The Mississippi PSC suspended each of these filings to allow more time for review.

On February 7, 2018, Mississippi Power submitted its revised 2018 projected PEP filing to the Mississippi PSC, which reflected the impacts of the Tax Reform Legislation, requesting an increase in annual retail revenues of $26 million based on a performance adjusted ROE of 9.33% and an increased equity ratio of 55%.

On March 22, 2018, Mississippi Power submitted its annual PEP lookback filing for 2017, which reflected no surcharge or refund.

On July 27, 2018, Mississippi Power and the Mississippi Public Utilities Staff (MPUS) entered into a settlement agreement with respect to the 2018 PEP filing and all unresolved PEP filings for prior years (PEP Settlement

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Agreement), which was approved by the Mississippi PSC on August 7, 2018. Rates under the PEP Settlement Agreement will take effect for the first billing cycle of September 2018.

The PEP Settlement Agreement provides for an increase of approximately $21.6 million in annual base retail revenues, which excludes approximately $5.5 million requested for certain compensation costs contested by the MPUS. Under the PEP Settlement Agreement, Mississippi Power expects to defer these costs for 2018 and 2019 as a regulatory asset. The Mississippi PSC is currently expected to rule on the appropriate treatment for such costs in connection with Mississippi Power's next base rate case, which is scheduled to be filed in the fourth quarter 2019 (2019 Base Rate Case). The ultimate outcome of this matter cannot be determined at this time.

Pursuant to the PEP Settlement Agreement, Mississippi Power's performance-adjusted allowed ROE will be 9.31% and its allowed equity ratio will remain at 50%, pending further review by the Mississippi PSC. In lieu of the requested equity ratio increase, Mississippi Power will retain $44 million of excess accumulated deferred income taxes resulting from the Tax Reform Legislation, which had been proposed to be amortized beginning in 2018, until the conclusion of the 2019 Base Rate Case. Further, Mississippi Power will seek equity contributions sufficient to restore its equity ratio (which was 43.5% at June 30, 2018) to the 50% target. In the event Mississippi Power's actual average equity ratio for 2018 is more than 1% higher or lower than the 50% target, Mississippi Power will defer the corresponding difference in its revenue requirement as a regulatory asset or liability for resolution in the 2019 Base Rate Case.

Pursuant to the PEP Settlement Agreement, PEP proceedings will be suspended until after the conclusion of the 2019 Base Rate Case and Mississippi Power will not be required to make any PEP filings for regulatory years 2018, 2019, and 2020. The PEP Settlement Agreement also resolves all open PEP filings with no change to customer rates. As a result, in the third quarter 2018, Mississippi Power expects to recognize revenues of $5 million previously reserved in connection with the 2012 PEP lookback filing.

Energy Efficiency

On May 8, 2018, the Mississippi PSC issued an order approving Mississippi Power's revised annual projected Energy Efficiency Cost Rider 2018 compliance filing, submitted on May 3, 2018, which increased annual retail revenues by approximately $3 million effective with the first billing cycle for June 2018.

Environmental Compliance Overview Plan

On August 3, 2018, Mississippi Power and the MPUS entered into a settlement agreement with respect to the 2018 ECO Plan filing (ECO Settlement Agreement), which provides for an increase of approximately $17 million in annual base retail revenues and was approved by the Mississippi PSC on August 7, 2018. Rates under the ECO Settlement Agreement will take effect for the first billing cycle of September 2018 and will continue in effect until modified by the Mississippi PSC. These revenues are expected to be sufficient to recover the costs included in Mississippi Power's request for 2018, as well as the remaining deferred amounts that were originally expected to be recovered in 2019. In accordance with the ECO Settlement Agreement, ECO Plan proceedings will be suspended until after the conclusion of the 2019 Base Rate Case and Mississippi Power will not be required to make any ECO Plan filings for 2018, 2019, and 2020, with any necessary true-ups to be reflected in the 2019 Base Rate Case. The ECO Settlement Agreement contains the same terms as the PEP Settlement Agreement described herein with respect to allowed ROE and equity ratio.

Ad Valorem Tax Adjustment

On May 8, 2018, the Mississippi PSC approved Mississippi Power's annual ad valorem tax adjustment factor filing for 2018, which included an annual rate increase of 0.8%, or $7 million, in annual retail revenues effective with the first billing cycle for June 2018, primarily due to increased assessments.

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Southern Company Gas

See Note 3 to the financial statements of Southern Company and Southern Company Gas under "Regulatory Matters – Southern Company Gas" and "Regulatory Matters," respectively, in Item 8 of the Form 10-K for additional information regarding Southern Company Gas' regulatory matters.

Riders

On April 19, 2018, the Illinois Commission approved Nicor Gas' variable income tax adjustment rider. This rider provides for refund or recovery of changes in income tax expense that result from income tax rates that differ from those used in Nicor Gas' last rate case. Customer refunds began on July 1, 2018 related to the January 1, 2018 through May 4, 2018 impacts of the Tax Reform Legislation. The impact of the Tax Reform Legislation subsequent to May 4, 2018 was addressed in Nicor Gas' approved rehearing request discussed herein under "Settled Base Rate Cases."

Natural Gas Cost Recovery

Southern Company Gas has established natural gas cost recovery rates approved by the relevant state regulatory agencies in the states in which it serves. Natural gas cost recovery revenues are adjusted for differences in actual recoverable natural gas costs and amounts billed in current regulated rates. Changes in the billing factor will not have a significant effect on Southern Company's or Southern Company Gas' revenues or net income, but will affect cash flows.

Base Rate Cases

Settled Base Rate Cases

In October 2017, Florida City Gas filed a general base rate case with the Florida PSC requesting an annual revenue increase of$19 million, which included an interim rate increase of $5 million annually that was approved and became effective January 12, 2018, subject to refund. On March 26, 2018, the Florida PSC approved a settlement that, after including the impact of the Tax Reform Legislation, provides for an $11.5 million increase in annual base rate revenues, effective June 1, 2018, based on a ROE of 10.19%.

On February 23, 2018, Atlanta Gas Light revised its annual base rate filing to reflect the impacts of the Tax Reform Legislation and requested a $16 million rate reduction in 2018. On May 15, 2018, the Georgia PSC approved a stipulation for Atlanta Gas Light's annual base rates to remain at the 2017 level for 2018 and 2019, with customer credits of $8 million in each of July 2018 and October 2018 to reflect the impacts of the Tax Reform Legislation. The Georgia PSC maintained Atlanta Gas Light's previously authorized earnings band based on a ROE between 10.55% and 10.95% and increased the allowed equity ratio by 4% to an equity ratio of 55% to address the negative cash flow and credit metric impacts of the Tax Reform Legislation. Additionally, Atlanta Gas Light is required to file a traditional base rate case on or before June 1, 2019 for rates effective January 1, 2020.

On May 2, 2018, the Illinois Commission approved Nicor Gas' rehearing request for revised base rates to incorporate the reduction in the federal income tax rate as a result of the Tax Reform Legislation. The resulting decrease of approximately$44 million in annual base rate revenues became effective May 5, 2018. Nicor Gas' previously-authorized capital structure and ROE of9.8% were not addressed in the rehearing and remain unchanged. The impact of the Tax Reform Legislation prior to May 5, 2018 was addressed in the variable income tax rider discussed herein under "Riders."

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Pending Base Rate Case

On February 15, 2018, Chattanooga Gas filed a general base rate case with the Tennessee Public Utility Commission (PUC) requesting a $7 million increase in annual base rate revenues. The requested increase, which, in accordance with a Tennessee PUC order, incorporated the effects of the Tax Reform Legislation, was based on a projected test year ending June 30, 2019 and a ROE of 11.25%. The Tennessee PUC is expected to rule on the requested increase in the third quarter 2018.

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

Other

The New Jersey BPU, Maryland PSC, and Virginia Commission each issued an order effective January 1, 2018 that requires utilities in their respective states to defer as a regulatory liability the impact of the Tax Reform Legislation, including the reduction in the corporate income tax rate to 21% and the impact of the flowback of excess deferred income taxes. On June 22, 2018, the New Jersey BPU approved a $12 million reduction in Elizabethtown Gas' annual base rate revenues. On March 28, 2018, the Maryland PSC approved a $0.1 million reduction in Elkton Gas' annual base rate revenues effective April 1, 2018. Credits were issued to customers in Maryland in May 2018 and will be issued to customers in New Jersey in the third quarter 2018 for the impact of the Tax Reform Legislation on the January 2018 through March 2018 billing periods.

On April 25, 2018, the Virginia Commission issued an order indicating that any proposal beyond a proposed base rate reduction to reflect the cost savings from the Tax Reform Legislation must be made through a general base rate case. Virginia Natural Gas expects to address the cost savings from the Tax Reform Legislation in the third quarter 2018 by filing an annual information form. The Virginia Commission is expected to rule on the impact of the Tax Reform Legislation by the first half of 2019. The ultimate outcome of this matter cannot be determined at this time.

Regulatory Infrastructure Programs

Southern Company Gas is engaged in various infrastructure programs that update or expand its gas distribution systems to improve reliability and help ensure the safety of its utility infrastructure, and recovers in rates its investment and a return associated with these infrastructure programs. See Note 3 to the financial statements of Southern Company and Southern Company Gas under "Regulatory Matters – Southern Company Gas – Regulatory Infrastructure Programs" and "Regulatory Matters – Regulatory Infrastructure Programs," respectively, in Item 8 of the Form 10-K for additional information.

Atlanta Gas Light's Pipeline Replacement Program

One of the capital projects under Atlanta Gas Light's Pipeline Replacement Program experienced construction issues and Atlanta Gas Light was required to complete mitigation work prior to placing it in service. In the first quarter 2018, Atlanta Gas Light recovered $7 million from the final settlement of contractor litigation claims. Mitigation costs recovered through the legal process are retained by Atlanta Gas Light. For additional information on the Pipeline Replacement Program settlement, see Note 3 to the financial statements of Southern Company Gas under "Regulatory Matters – PRP Settlement" in Item 8 of the Form 10-K.

Nuclear Construction

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

In 2009, the Georgia PSC certified construction of Plant Vogtle Units 3 and 4. In 2012, the NRC issued the related combined construction and operating licenses, which allowed full construction of the two AP1000 nuclear units (with electric generating capacity of approximately 1,100 MWs each) and related facilities to begin. Until March 2017, construction on Plant Vogtle Units 3 and 4 continued under the Vogtle 3 and 4 Agreement, which was a

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substantially fixed price agreement. In March 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code.

In connection with the EPC Contractor's bankruptcy filing, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into the Interim Assessment Agreement with the EPC Contractor to allow construction to continue. The Interim Assessment Agreement expired in July 2017 when Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the EPC Contractor entered into the Vogtle Services Agreement. Under the Vogtle Services Agreement, Westinghouse provides facility design and engineering services, procurement and technical support, and staff augmentation on a time and materials cost basis. The Vogtle Services Agreement will continue until the start-up and testing of Plant Vogtle Units 3 and 4 are complete and electricity is generated and sold from both units. The Vogtle Services Agreement is terminable by the Vogtle Owners upon 30 days' written notice.

In October 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into a construction completion agreement with Bechtel, whereby Bechtel will serve as the primary contractor for the remaining construction activities for Plant Vogtle Units 3 and 4 (Bechtel Agreement). The Bechtel Agreement is a cost reimbursable plus fee arrangement, whereby Bechtel is reimbursed for actual costs plus a base fee and an at-risk fee, which is subject to adjustment based on Bechtel's performance against cost and schedule targets. Each Vogtle Owner is severally (not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to Bechtel under the Bechtel Agreement. The Vogtle Owners may terminate the Bechtel Agreement at any time for their convenience, provided that the Vogtle Owners will be required to pay amounts related to work performed prior to the termination (including the applicable portion of the base fee), certain termination-related costs, and, at certain stages of the work, the applicable portion of the at-risk fee. Bechtel may terminate the Bechtel Agreement under certain circumstances, including certain Vogtle Owner suspensions of work, certain breaches of the Bechtel Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events. Pursuant to the Loan Guarantee Agreement between Georgia Power and the DOE, Georgia Power is required to obtain the DOE's approval of the Bechtel Agreement prior to obtaining any further advances under the Loan Guarantee Agreement.

In December 2017, the Georgia PSC approved Georgia Power's seventeenth VCM report, which included a recommendation to continue construction of Plant Vogtle Units 3 and 4, with Southern Nuclear serving as project manager and Bechtel serving as the primary construction contractor.

Cost and Schedule

In preparation for its nineteenth VCM filing, Georgia Power requested Southern Nuclear to perform a full cost reforecast for the project. Georgia Power's approximate proportionate share of the remaining estimated capital cost to complete Plant Vogtle Units 3 and 4 by the expected in-service dates of November 2021 and November 2022, respectively, is as follows:

	(in billions)
Base project capital cost forecast(a)(b)	$	8.0
Construction contingency estimate	0.4
Total project capital cost forecast(a)(b)	8.4
Net investment as of June 30, 2018(b)	(4.0		)
Remaining estimate to complete(a)	$	4.4

(a) Excludes financing costs expected to be capitalized through AFUDC of approximately $350 million.

(b) Net of $1.7 billion received from Toshiba in 2017 under the Guarantee Settlement Agreement and $188 million in Customer Refunds recognized as a regulatory liability in 2017.

Georgia Power estimates that its financing costs for construction of Plant Vogtle Units 3 and 4 will total approximately $3.2 billion, of which $1.7 billion had been incurred through June 30, 2018.

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The $0.7 billion increase to the base capital cost forecast reflected in the table above primarily results from changed assumptions related to the finalization of contract scopes and management responsibilities for Bechtel and over 60 subcontractors, labor productivity rates, and craft labor incentives, as well as the related levels of project management, oversight, and support, including field supervision and engineering support.

Although Georgia Power believes these incremental costs are reasonable and necessary to complete the project and the Georgia PSC's order in the seventeenth VCM proceeding specifically states that the construction of Plant Vogtle Units 3 and 4 is not subject to a cost cap, Georgia Power does not intend to seek rate recovery for these cost increases included in the current base capital cost forecast (or any related financing costs), which will be filed with the Georgia PSC in the nineteenth VCM report at the end of August 2018. In connection with future VCM filings, Georgia Power may request the Georgia PSC to evaluate costs currently included in the construction contingency estimate for rate recovery as and when they are appropriately included in the base capital cost forecast. After considering the significant level of uncertainty that exists regarding the future recoverability of costs included in the construction contingency estimate since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in these future regulatory proceedings, Georgia Power has recorded a total pre-tax charge to income of $1.1 billion ($0.8 billion after tax), which includes the total increase in the capital cost forecast and construction contingency estimate as of June 30, 2018.

Subsequent to the EPC Contractor bankruptcy filing, a number of subcontractors to the EPC Contractor alleged non-payment by the EPC Contractor for amounts owed for work performed on Plant Vogtle Units 3 and 4. Georgia Power, acting for itself and as agent for the Vogtle Owners, has taken actions to remove liens filed by these subcontractors through the posting of surety bonds. Related to such liens, certain subcontractors have filed, and additional subcontractors may file, lawsuits against the EPC Contractor and the Vogtle Owners to preserve their payment rights with respect to such claims. All known amounts associated with the removal of subcontractor liens and other EPC Contractor pre-petition accounts payable have been paid or accrued as of June 30, 2018. The ultimate liability is expected to be finalized in connection with the completion of the sale of Westinghouse.

As construction continues, challenges with management of contractors, subcontractors, and vendors; labor productivity, availability, and/or cost escalation; procurement, fabrication, delivery, assembly, and/or installation, including any required engineering changes, of plant systems, structures, and components (some of which are based on new technology that is just beginning initial operation in the global nuclear industry at this scale); or other issues could arise and change the projected schedule and estimated cost.

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. 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, 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.

The ultimate outcome of these matters cannot be determined at this time. However, any extension of the project schedule is currently estimated to result in additional base capital costs of approximately $50 million per month, based on Georgia Power's ownership interests, and AFUDC of approximately $12 million per month. While Georgia Power is not precluded from seeking recovery of any future capital cost forecast increase, management will ultimately determine whether or not to seek recovery. Any further changes to the capital cost forecast that are not expected to be recoverable through regulated rates will be required to be charged to income and such charges could be material.

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Joint Owner Contracts

In November 2017, the Vogtle Owners entered into an amendment to their joint ownership agreements for Plant Vogtle Units 3 and 4 (as amended, Vogtle Joint Ownership Agreements) to provide for, among other conditions, additional Vogtle Owner approval requirements. Pursuant to the Vogtle Joint Ownership Agreements, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction if certain adverse events occur, including: (i) the bankruptcy of Toshiba; (ii) termination or rejection in bankruptcy of certain agreements, including the Vogtle Services Agreement or the Bechtel Agreement; (iii) the Georgia PSC or Georgia Power determines that any of Georgia Power's costs relating to the construction of Plant Vogtle Units 3 and 4 will not be recovered in retail rates because such costs are deemed unreasonable or imprudent; or (iv) an increase in the construction budget contained in the seventeenth VCM report of more than $1 billion or extension of the project schedule contained in the seventeenth VCM report of more than one year. In addition, pursuant to the Vogtle Joint Ownership Agreements, the required approval of holders of ownership interests in Plant Vogtle Units 3 and 4 is at least (i) 90% for a change of the primary construction contractor and (ii) 67% for material amendments to the Vogtle Services Agreement or agreements with Southern Nuclear or the primary construction contractor, including the Bechtel Agreement. The Vogtle Joint Ownership Agreements also confirm that the Vogtle Owners' sole recourse against Georgia Power or Southern Nuclear for any action or inaction in connection with their performance as agent for the Vogtle Owners is limited to removal of Georgia Power and/or Southern Nuclear as agent, except in cases of willful misconduct.

As a result of the increase in the total project capital cost forecast and Georgia Power's decision not to seek rate recovery of the increase in the base capital costs as described in "Cost and Schedule" herein, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction. The Vogtle Owners are expected to conduct these votes in the third quarter 2018.

If the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 do not vote to continue construction, the Vogtle Joint Ownership Agreements provide that the project will be cancelled, and construction will cease. In the event that fewer than 90% of the Vogtle Owners vote to continue construction, Georgia Power and the other Vogtle Owners will assess options for Plant Vogtle Units 3 and 4. If Plant Vogtle Units 3 and 4 were cancelled and Georgia Power was unable to recover costs it has incurred in connection with the project, Southern Company's and Georgia Power's results of operations, cash flow, and financial condition would be materially impacted. The ultimate outcome of this matter cannot be determined at this time.

Regulatory Matters

In 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4 with a certified capital cost of $4.418 billion. In addition, in 2009 the Georgia PSC approved inclusion of the Plant Vogtle Units 3 and 4 related CWIP accounts in rate base, and the State of Georgia enacted the Georgia Nuclear Energy Financing Act, which allows Georgia Power to recover financing costs for Plant Vogtle Units 3 and 4. Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff up to the certified capital cost of $4.418 billion. As of June 30, 2018, Georgia Power had recovered approximately $1.7 billion of financing costs. Financing costs related to capital costs above $4.418 billion will be recovered through AFUDC; however, Georgia Power will not record AFUDC related to any capital costs in excess of the total deemed reasonable by the Georgia PSC (currently $7.3 billion) and not requested for rate recovery.

Georgia Power is required to file semi-annual VCM reports with the Georgia PSC by February 28 and August 31 of each year. In 2013, in connection with the eighth VCM report, the Georgia PSC approved a stipulation between Georgia Power and the staff of the Georgia PSC to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate in accordance with the 2009 certification order until the completion of Plant Vogtle Unit 3, or earlier if deemed appropriate by the Georgia PSC and Georgia Power.

In 2016, the Georgia PSC voted to approve a settlement agreement (Vogtle Cost Settlement Agreement) resolving certain prudency matters in connection with the fifteenth VCM report. In December 2017, the Georgia PSC voted to approve (and issued its related order on January 11, 2018) certain recommendations made by Georgia Power in the

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seventeenth VCM report and modifying the Vogtle Cost Settlement Agreement. The Vogtle Cost Settlement Agreement, as modified by the January 11, 2018 order, resolved the following regulatory matters related to Plant Vogtle Units 3 and 4: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report should be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement was reasonable and prudent and none of the amounts paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) (a) capital costs incurred up to $5.68 billion would be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, (b) Georgia Power would have the burden to show that any capital costs above $5.68 billion were prudent, and (c) a revised capital cost forecast of $7.3 billion (after reflecting the impact of payments received under the Guarantee Settlement Agreement and Customer Refunds) was found reasonable; (iv) construction of Plant Vogtle Units 3 and 4 should be completed, with Southern Nuclear serving as project manager and Bechtel as primary contractor; (v) approved and deemed reasonable Georgia Power's revised schedule placing Plant Vogtle Units 3 and 4 in service in November 2021 and November 2022, respectively; (vi) confirmed that the revised cost forecast does not represent a cost cap and that prudence decisions on cost recovery will be made at a later date, consistent with applicable Georgia law; (vii) reduced the ROE used to calculate the NCCR tariff (a) from 10.95% (the ROE rate setting point authorized by the Georgia PSC in the 2013 ARP) to 10.00% effective January 1, 2016, (b) from 10.00% to 8.30%, effective January 1, 2020, and (c) from 8.30% to 5.30%, effective January 1, 2021 (provided that the ROE in no case will be less than Georgia Power's average cost of long-term debt); (viii) reduced the ROE used for AFUDC equity for Plant Vogtle Units 3 and 4 from 10.00% to Georgia Power's average cost of long-term debt, effective January 1, 2018; and (ix) agreed that upon Unit 3 reaching commercial operation, retail base rates would be adjusted to include carrying costs on those capital costs deemed prudent in the Vogtle Cost Settlement Agreement. The January 11, 2018 order also stated that if Plant Vogtle Units 3 and 4 are not commercially operational by June 1, 2021 and June 1, 2022, respectively, the ROE used to calculate the NCCR tariff will be further reduced by 10 basis points each month (but not lower than Georgia Power's average cost of long-term debt) until the respective unit is commercially operational. The ROE reductions negatively impacted earnings by approximately $25 million in 2017 and are estimated to have negative earnings impacts of approximately $100 million in 2018 and an aggregate of $585 million from 2019 to 2022.

In its January 11, 2018 order, the Georgia PSC also stated if other conditions change and assumptions upon which Georgia Power's seventeenth VCM report are based do not materialize, the Georgia PSC reserved the right to reconsider the decision to continue construction.

On February 12, 2018, Georgia Interfaith Power & Light, Inc. and Partnership for Southern Equity, Inc. filed a petition appealing the Georgia PSC's January 11, 2018 order with the Fulton County Superior Court. On March 8, 2018, Georgia Watch filed a similar appeal to the Fulton County Superior Court for judicial review of the Georgia PSC's final decision and denial of Georgia Watch's motion for reconsideration. Georgia Power believes the two appeals have no merit; however, an adverse outcome in either appeal could have a material impact on Southern Company's and Georgia Power's results of operations, financial condition, and liquidity.

The Georgia PSC has approved seventeen VCM reports covering the periods through June 30, 2017, including total construction capital costs incurred through that date of $4.4 billion. On August 21, 2018, the Georgia PSC is scheduled to vote on Georgia Power's eighteenth VCM report, which requested approval of $448 million of construction capital costs (excluding the $1.7 billion received from Toshiba under the Guarantee Settlement Agreement and the $188 million in Customer Refunds recognized as a regulatory liability) incurred from July 1, 2017 through December 31, 2017.

On August 31, 2018, Georgia Power will file its nineteenth VCM report with the Georgia PSC, which will reflect the revised capital cost forecast discussed previously and request approval of $578 million of construction capital costs incurred from January 1, 2018 through June 30, 2018.

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

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DOE Financing

As of June 30, 2018, Georgia Power had borrowed $2.6 billion related to Plant Vogtle Units 3 and 4 costs through the Loan Guarantee Agreement and a multi-advance credit facility among Georgia Power, the DOE, and the FFB, which provides for borrowings of up to $3.46 billion, subject to the satisfaction of certain conditions. In September 2017, the DOE issued a conditional commitment to Georgia Power for up to approximately $1.67 billion in additional guaranteed loans under the Loan Guarantee Agreement. In June 2018, the DOE approved a request by Georgia Power to extend the conditional commitment to September 30, 2018. Any further extension must be approved by the DOE. Final approval and issuance of these additional loan guarantees by the DOE cannot be assured and are subject to the negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions, including the Vogtle Owners' votes to continue construction. See Note 6 to the financial statements of Southern Company and Georgia Power under "DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K and Note (F) under "DOE Loan Guarantee Borrowings" for additional information, including applicable covenants, events of default, mandatory prepayment events (including any decision not to continue construction of Plant Vogtle Units 3 and 4), and conditions to borrowing.

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

Kemper County Energy Facility

For additional information on the Kemper County energy facility, see Note 3 to the financial statements of Southern Company and Mississippi Power under "Kemper County Energy Facility" in Item 8 of the Form 10-K.

As the mining permit holder for the Kemper County energy facility, Liberty Fuels Company, LLC has a legal obligation to perform mine reclamation, and Mississippi Power has a contractual obligation to fund all reclamation activities. Mine reclamation began in the first quarter 2018. See Note 1 to the financial statements of Southern Company and Mississippi Power under "Asset Retirement Obligations and Other Costs of Removal" and of Mississippi Power under "Variable Interest Entities" in Item 8 of the Form 10-K for additional information.

As of June 30, 2018, Mississippi Power recorded charges to income of an immaterial amount for the second quarter 2018 and $45 million ($33 million after tax) for year-to-date 2018, primarily resulting from the abandonment and related closure activities for the mine and gasifier-related assets at the Kemper County energy facility. Additional closure costs for the mine and gasifier-related assets, currently estimated to cost up to $25 million pre-tax (excluding salvage, net of dismantlement costs), are expected to be incurred during the remainder of 2018 and 2019. In addition, period costs, including, but not limited to, costs for compliance and safety, ARO accretion, and property taxes for the mine and gasifier-related assets, are estimated at $4 million for the remainder of 2018, $7 million in 2019, and $4 million annually beginning in 2020. The ultimate outcome of this matter cannot be determined at this time.

Reserve Margin Plan

On August 6, 2018, Mississippi Power filed its proposed RMP, as required by the Mississippi PSC's order in the docket established for the purposes of pursuing a global settlement of the costs related to the Kemper County energy facility. Under the RMP, Mississippi Power proposes alternatives that would reduce its reserve margin, with the most economic of the alternatives being the2-year and 7-year acceleration of the retirement of Plant Watson Units 4 and 5, respectively, to the first quarter 2022 and the 4-year acceleration of the retirement of Plant Greene County Units 1 and 2 to the third quarter 2021 and the third quarter 2022, respectively, in order to lower or avoid operating costs. The Plant Greene County unit retirements would require the completion by Alabama Power of proposed transmission and system reliability improvements, as well as agreement by Alabama Power. The RMP filing also states that, in the event the Mississippi PSC ultimately approves an alternative that includes an accelerated retirement, Mississippi Power would require authorization to defer in a regulatory asset for future recovery the remaining net book value of the units at the time of retirement. Mississippi Power expects the MPUS and other interested parties to review the proposal prior to resolution by the Mississippi PSC. The ultimate outcome of this matter cannot be determined at this time. However, if approved by the Mississippi PSC, the alternatives are not expected to have any adverse impact on customer rates.

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Other Matters

Investments in Leveraged Leases

See Note 1 to the financial statements of Southern Company under "Leveraged Leases" in Item 8 of the Form 10-K for additional information regarding a Southern Company Holdings Inc. (Southern Holdings) subsidiary's leveraged lease agreements and concerns about the financial and operational performance of one of the lessees and the associated generation assets.

The ability of the lessees to make required payments to the Southern Holdings subsidiary is dependent on the operational performance of the assets. As a result of operational improvements in the first half of 2018, the June 2018 lease payment was paid in full and the December 2018 lease payment is currently expected to be paid in full. However, operational issues and the resulting cash liquidity challenges persist and significant concerns continue regarding the lessee's ability to make the remaining semi-annual lease payments. These operational challenges may also impact the expected residual value of the assets at the end of the lease term in 2047. If any future lease payment is not paid in full, the Southern Holdings subsidiary may be unable to make its corresponding payment to the holders of the underlying non-recourse debt related to the generation assets. Failure to make the required payment to the debtholders would represent an event of default that would give the debtholders the right to foreclose on, and take ownership of, the generation assets from the Southern Holdings subsidiary, in effect terminating the lease and resulting in the write-off of the related lease receivable, which would result in a reduction in net income of approximately $86 million after tax based on the lease receivable balance as of June 30, 2018. Southern Company has evaluated the recoverability of the lease receivable and the expected residual value of the generation assets at the end of the lease under various scenarios and has concluded that its investment in the leveraged lease is not impaired as of June 30, 2018. Southern Company will continue to monitor the operational performance of the underlying assets and evaluate the ability of the lessee to continue to make the required lease payments. The ultimate outcome of this matter cannot be determined at this time.

Natural Gas Storage

A wholly-owned subsidiary of Southern Company Gas owns and operates a natural gas storage facility consisting of two salt dome caverns in Louisiana. Periodic integrity tests are required in accordance with rules of the Louisiana Department of Natural Resources (DNR). In August 2017, in connection with an ongoing integrity project, updated seismic mapping indicated the proximity of one of the caverns to the edge of the salt dome may be less than the required minimum and could result in Southern Company Gas retiring the cavern early. At June 30, 2018, the facility's property, plant, and equipment had a net book value of $111 million, of which the cavern itself represents approximately 20%. A potential early retirement of this cavern is dependent upon several factors including compliance with an order from the Louisiana DNR detailing the requirements to place the cavern back in service, which includes, among other things, obtaining core samples to determine the composition of the sheath surrounding the edge of the salt dome.

The cavern continues to maintain its pressures and overall structural integrity. Southern Company Gas intends to monitor the cavern and comply with the Louisiana DNR order through 2020 and place the cavern back in service in 2021. These events were considered in connection with Southern Company Gas' 2017 long-lived asset impairment analysis, which determined there was no impairment. Any future changes in results of monitoring activities, rates at which expiring capacity contracts are re-contracted, timing of placing the cavern back in service, or Louisiana DNR requirements could trigger impairment. Further, early retirement of the cavern could trigger impairment of other long-lived assets associated with the natural gas storage facility. The ultimate outcome of this matter cannot be determined at this time, but could have a significant impact on Southern Company's financial statements and a material impact on Southern Company Gas' financial statements.

(C) REVENUE FROM CONTRACTS WITH CUSTOMERS

The registrants generate revenues from a variety of sources, some of which are excluded from the scope of ASC 606, such as leases, derivatives, and certain cost recovery mechanisms. See Note (A) under "Recently Adopted

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Accounting Standards – Revenue" for additional information on the adoption of ASC 606 for revenue from contracts with customers.

The majority of the revenues of the traditional electric operating companies and Southern Company Gas are generated from contracts with retail electric and natural gas distribution customers. Revenues from this integrated service to deliver electricity or gas when and if called upon by the customer is recognized as a single performance obligation satisfied over time and is recognized at a tariff rate as electricity or gas is delivered to the customer during the month. The traditional electric operating companies and Southern Company Gas exclude taxes imposed on the customer and collected on behalf of governmental agencies to be remitted to these agencies from the transaction price in determining the revenue related to contracts with a customer.

The traditional electric operating companies and Southern Power also have contracts with multiple performance obligations, such as capacity and energy in a wholesale PPA, where the contract's total transaction price is allocated to each performance obligation based on the standalone selling price. The standalone selling price is primarily determined by the price charged to customers for the specific goods or services transferred with the performance obligations. Generally, the registrants recognize revenue as the performance obligations are satisfied over time as electricity or natural gas is delivered to the customer or as generation capacity is available to the customer. At Southern Company Gas, the performance obligations related to wholesale gas services are satisfied, and revenue is recognized, at a point in time when natural gas is delivered to the customer.

The registrants generally have a right to consideration in an amount that corresponds directly with the value to the customer of the entity's performance completed to date and may recognize revenue in the amount to which the entity has a right to invoice and has elected to recognize revenue for its sales of electricity, capacity, and natural gas using the invoice practical expedient. In addition, payment for goods and services rendered is typically due in the subsequent month following satisfaction of the registrants' performance obligation.

216

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(UNAUDITED)

The following tables disaggregate revenue sources for the three and six months ended June 30, 2018:

	For the Three Months Ended June 30, 2018			For the Six Months Ended June 30, 2018
	(in millions)
Southern Company
Operating revenues
Retail electric revenues(a)
Residential	$	1,579		$	3,118
Commercial	1,315			2,557
Industrial	814			1,569
Other	32			64
Natural gas distribution revenues	642			1,865
Alternative revenue programs(b)	(4		)	(27		)
Total retail electric and gas distribution revenues	$	4,378		$	9,146
Wholesale energy revenues(c)(d)	459			928
Wholesale capacity revenues(d)	152			302
Other natural gas revenues(e)	68			476
Other revenues(f)	570			1,147
Total operating revenues	$	5,627		$	11,999

(a) Retail electric revenues include $18 million and $36 million of leases for the three and six months ended June 30, 2018, respectively, and a net increase of $68 million and $101 million for the three and six months ended June 30, 2018, respectively, from certain cost recovery mechanisms that are not accounted for as revenue under ASC 606. See Note 3 to the financial statements of Southern Company under "Regulatory Matters" in Item 8 of the Form 10-K for additional information on cost recovery mechanisms.

(b) See Note 1 to the financial statements of Southern Company under "Revenues" in Item 8 of the Form 10-K for additional information on alternative revenue programs at the natural gas distribution utilities. Alternative revenue program revenues are presented net of any previously recognized program amounts billed to customers during the same accounting period.

(c) Wholesale energy revenues include $61 million and $155 million for the three and six months ended June 30, 2018, respectively, of revenues accounted for as derivatives, primarily related to physical energy sales in the wholesale electricity market. See Note (I) for additional information on energy-related derivative contracts.

(d) Wholesale energy and wholesale capacity revenues include $118 million and $31 million, respectively, for the three months ended June 30, 2018 and $187 million and $61 million, respectively, for the six months ended June 30, 2018 of PPA contracts accounted for as leases.

(e) Other natural gas revenues related to Southern Company Gas' energy and risk management activities are presented net of the related costs of those activities and include gross third-party revenues of $1.3 billion and $3.3 billion for the three and six months ended June 30, 2018, respectively, of which $0.7 billion and $1.8 billion, respectively, relates to contracts that are accounted for as derivatives. See Note (L) under "Southern Company Gas" for additional information on the components of wholesale gas services operating revenues.

(f) Other revenues include $89 million and $183 million for the three and six months ended June 30, 2018, respectively, of revenues not accounted for under ASC 606.

217

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

	Alabama Power		Georgia Power		Gulf Power		Mississippi Power
	(in millions)
For the Three Months Ended June 30, 2018
Operating revenues
Retail revenues(a)(b)
Residential	$	557	$	785	$	172	$	65
Commercial	402		749		96		68
Industrial	372		335		31		76
Other	7		20		2		3
Total retail electric revenues	$	1,338	$	1,889	$	301	$	212
Wholesale energy revenues(c)	71		26		21		73
Wholesale capacity revenues	25		13		6		1
Other revenues(b)(d)	69		120		16		11
Total operating revenues	$	1,503	$	2,048	$	344	$	297
For the Six Months Ended June 30, 2018
Operating revenues
Retail revenues(a)(b)
Residential	$	1,127	$	1,529	$	337	$	125
Commercial	774		1,466		188		130
Industrial	710		650		63		146
Other	13		43		3		5
Total retail electric revenues	$	2,624	$	3,688	$	591	$	406
Wholesale energy revenues(c)	172		66		56		167
Wholesale capacity revenues	49		27		12		5
Other revenues(b)(d)	131		227		33		20
Total operating revenues	$	2,976	$	4,008	$	692	$	598

(a) Retail revenues at Alabama Power, Georgia Power, Gulf Power, and Mississippi Power include a net increase or (net reduction) of $78 million, $3 million, $(12) million, and $(1) million, respectively, for the three months ended June 30, 2018 and $125 million, $12 million, $(28) million, and $(8) million, respectively, for the six months ended June 30, 2018 related to certain cost recovery mechanisms that are not accounted for as revenue under ASC 606. See Note 3 to the financial statements of Alabama Power, Georgia Power, Gulf Power, and Mississippi Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information on cost recovery mechanisms.

(b) Retail revenues and other revenues at Georgia Power include $18 million and $33 million, respectively, for the three months ended June 30, 2018 and $36 million and $66 million, respectively, for the six months ended June 30, 2018 of revenues accounted for as leases.

(c) Wholesale energy revenues at Alabama Power and Georgia Power include $4 million and $5 million, respectively, for the three months ended June 30, 2018 and $9 million and $13 million, respectively, for the six months ended June 30, 2018 accounted for as derivatives primarily related to physical energy sales in the wholesale electricity market. See Note (I) for additional information on energy-related derivative contracts.

(d) Other revenues at Alabama Power, Georgia Power, and Gulf Power include $26 million, $26 million, and $2 million, respectively, for the three months ended June 30, 2018 and $52 million, $53 million, and $4 million, respectively, for the six months ended June 30, 2018 of revenues not accounted for under ASC 606.

218

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

	For the Three Months Ended June 30, 2018		For the Six Months Ended June 30, 2018
	(in millions)
Southern Power
PPA capacity revenues(a)	$	144	$	282
PPA energy revenues(a)	302		556
Non-PPA revenues(b)	106		221
Other revenues	3		5
Total operating revenues	$	555	$	1,064

(a) PPA capacity revenues and PPA energy revenues include $47 million and $127 million, respectively, for the three months ended June 30, 2018 and $94 million and $203 million, respectively, for the six months ended June 30, 2018 related to PPAs accounted for as leases. See Note 1 to the financial statements of Southern Power under "Revenues" in Item 8 of the Form 10-K for additional information on capacity revenues accounted for as leases.

(b) Non-PPA revenues include $50 million and $129 million for the three and six months ended June 30, 2018, respectively, of revenues from short-term sales related to physical energy sales from uncovered capacity in the wholesale electricity market. See Note 1 to the financial statements of Southern Power under "Revenues" in Item 8 of the Form 10-K and Note (I) for additional information on energy-related derivative contracts.

	For the Three Months Ended June 30, 2018			For the Six Months Ended June 30, 2018
	(in millions)
Southern Company Gas
Operating revenues
Natural gas distribution revenues
Residential	$	273		$	933
Commercial	76			268
Transportation	7			24
Industrial	228			505
Other	58			135
Alternative revenue programs(a)	(4		)	(27		)
Total natural gas distribution revenues	$	638		$	1,838
Gas marketing services(b)	89			359
Wholesale gas services(c)	(15		)	131
Gas midstream operations	18			40
Other revenues	—			1
Total operating revenues	$	730		$	2,369

(a) See Note 1 to the financial statements of Southern Company Gas under "Revenues" in Item 8 of the Form 10-K for additional information on alternative revenue programs at the natural gas distribution utilities. Alternative revenue program revenues are presented net of any previously recognized program amounts billed to customers during the same accounting period.

(b) Gas marketing services includes $4 million for the six months ended June 30, 2018 of revenues not accounted for under ASC 606.

(c) Wholesale gas services revenues are presented net of the related costs associated with its energy trading and risk management activities. Operating revenues, as presented, include gross third-party revenues of $1.3 billion and $3.3 billion for the three and six months ended June 30, 2018, respectively, of which $0.7 billion and $1.8 billion, respectively, relates to contracts that are accounted for as derivatives. See Note (L) under "Southern Company Gas" for additional information on the components of wholesale gas services operating revenues and Note (I) for additional information on energy-related derivative contracts.

219

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Contract Balances

The following table reflects the closing balances of receivables, contract assets, and contract liabilities related to revenues from contracts with customers as of June 30, 2018:

	Receivables		Contract Assets		Contract Liabilities
	(in millions)
Southern Company	$	2,785	$	33	$	36
Alabama Power	603		—		10
Georgia Power	840		9		9
Gulf Power	169		—		1
Mississippi Power	83		—		—
Southern Power	136		—		4
Southern Company Gas	570		—		1

As of June 30, 2018, Alabama Power had contract liabilities for outstanding performance obligations primarily related to extended service agreements. Georgia Power had contract assets primarily related to unregulated service agreements where payment is contingent on project completion. Georgia Power had contract liabilities for outstanding performance obligations primarily related to fixed retail customer bill programs where the payment is contingent upon Georgia Power's continued performance and the customer's continued participation in the program over the one-year contract term. Southern Company's unregulated distributed generation business had $23 million and $16 million of contract assets and contract liabilities, respectively, remaining for outstanding performance obligations.

Remaining Performance Obligations

The traditional electric operating companies and Southern Power have long-term contracts with customers in which revenues are recognized as performance obligations are satisfied over the contract term. These contracts primarily relate to PPAs whereby the traditional electric operating companies and Southern Power provide electricity and generation capacity to a customer. The revenue recognized for the delivery of electricity is variable; however, certain PPAs include a fixed payment for fixed generation capacity over the term of the contract. Southern Company's unregulated distributed generation business also has partially satisfied performance obligations related to certain fixed price contracts. Revenues from contracts with customers related to these performance obligations remaining at June 30, 2018 are expected to be recognized as follows:

	2018		2019		2020		2021		2022		2023 and Thereafter
	(in millions)
Southern Company(*)	$	263	$	352	$	322	$	322	$	310	$	1,960
Alabama Power	11		22		22		26		23		161
Georgia Power	20		41		38		40		30		113
Gulf Power	11		22		—		—		—		—
Mississippi Power	2		3		3		1		—		—
Southern Power(*)	211		310		283		277		276		1,809

(*) Excludes amounts related to held for sale assets. See Note (J) under "Southern Company's Sale of Gulf Power" and "Southern Power – Sale of Florida Plants" for additional information.

220

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

(D) FAIR VALUE MEASUREMENTS

As of June 30, 2018, 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, 2018:	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(a)(b)	$	287	$	166	$	—	$	—	$	453
Foreign currency derivatives	—		132		—		—		132
Nuclear decommissioning trusts(c)	798		998		—		33		1,829
Cash equivalents	1,449		—		—		—		1,449
Other investments	9		—		1		—		10
Total	$	2,543	$	1,296	$	1	$	33	$	3,873
Liabilities:
Energy-related derivatives(a)(b)	$	422	$	151	$	—	$	—	$	573
Interest rate derivatives	—		68		—		—		68
Foreign currency derivatives	—		23		—		—		23
Contingent consideration	—		—		22		—		22
Total	$	422	$	242	$	22	$	—	$	686
Alabama Power
Assets:
Energy-related derivatives	$	—	$	8	$	—	$	—	$	8
Nuclear decommissioning trusts:(d)
Domestic equity	440		86		—		—		526
Foreign equity	61		55		—		—		116
U.S. Treasury and government agency securities	—		18		—		—		18
Corporate bonds	28		158		—		—		186
Mortgage and asset backed securities	—		18		—		—		18
Private equity	—		—		—		33		33
Other	7		—		—		—		7
Cash equivalents	495		—		—		—		495
Total	$	1,031	$	343	$	—	$	33	$	1,407
Liabilities:
Energy-related derivatives	$	—	$	9	$	—	$	—	$	9

221

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

	Fair Value Measurements Using:
As of June 30, 2018:	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	$	—	$	7	$	—	$	—	$	7
Nuclear decommissioning trusts:(d) (e)
Domestic equity	242		1		—		—		243
Foreign equity	—		135		—		—		135
U.S. Treasury and government agency securities	—		239		—		—		239
Municipal bonds	—		78		—		—		78
Corporate bonds	—		164		—		—		164
Mortgage and asset backed securities	—		41		—		—		41
Other	19		5		—		—		24
Total	$	261	$	670	$	—	$	—	$	931
Liabilities:
Energy-related derivatives	$	—	$	19	$	—	$	—	$	19
Interest rate derivatives	—		6		—		—		6
Total	$	—	$	25	$	—	$	—	$	25
Gulf Power
Assets:
Cash equivalents	$	27	$	—	$	—	$	—	$	27
Liabilities:
Energy-related derivatives	$	—	$	12	$	—	$	—	$	12
Mississippi Power
Assets:
Energy-related derivatives	$	—	$	3	$	—	$	—	$	3
Cash equivalents	205		—		—		—		205
Total	$	205	$	3	$	—	$	—	$	208
Liabilities:
Energy-related derivatives	$	—	$	9	$	—	$	—	$	9

222

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

	Fair Value Measurements Using:
As of June 30, 2018:	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	$	—	$	3	$	—	$	—	$	3
Foreign currency derivatives	—		132		—		—		132
Total	$	—	$	135	$	—	$	—	$	135
Liabilities:
Energy-related derivatives	$	—	$	3	$	—	$	—	$	3
Foreign currency derivatives	—		23		—		—		23
Contingent consideration	—		—		22		—		22
Total	$	—	$	26	$	22	$	—	$	48
Southern Company Gas
Assets:
Energy-related derivatives(a)(b)	$	287	$	144	$	—	$	—	$	431
Cash equivalents	1		—		—		—		1
Total	$	288	$	144	$	—	$	—	$	432
Liabilities:
Energy-related derivatives(a)(b)	$	422	$	99	$	—	$	—	$	521

(a) Excludes $3 million associated with premiums and certain weather derivatives accounted for based on intrinsic value rather than fair value.

(b) Excludes cash collateral of $183 million.

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

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

(e) Includes the investment securities pledged to creditors and collateral received and excludes payables related to the securities lending program. As of June 30, 2018, approximately $63 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 $14 million and $4 million, respectively, for the three and six months ended June 30, 2018 and increased by $55 million and $118 million, respectively, for the three and six months ended June 30, 2017. Alabama Power recorded an increase in fair value of $15 million and $10 million, respectively, for the three and six months ended June 30, 2018 and an increase of $28 million and $62 million, respectively, for the three and six months ended June 30, 2017 as a change in regulatory liabilities related to its AROs. Georgia Power recorded a decrease in fair value of $1 million and $6 million, respectively, for the three and six months ended June 30, 2018 and an increase of $27 million and $56 million, respectively, for the three and six months ended June 30, 2017 as a change in its regulatory asset related to its AROs.

223

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Valuation Methodologies

The energy-related derivatives primarily consist of exchange-traded and 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 reflects 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 reflects 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 data and valuations of similar instruments. See Note (I) 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.

Southern Power has contingent payment obligations related to certain acquisitions whereby Southern Power is primarily obligated to make generation-based payments to the seller, which commenced at the commercial operation date of the respective facility and continue through 2026. The obligation is categorized as Level 3 under Fair Value Measurements as the fair value is determined using significant unobservable inputs for the forecasted facility generation in MW-hours, as well as other inputs such as a fixed dollar amount per MW-hour, and a discount rate. The fair value of contingent consideration reflects the net present value of expected payments and any periodic change arising from forecasted generation is expected to be immaterial.

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

As of June 30, 2018, the fair value measurements of private equity investments held in the nuclear decommissioning trusts 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, 2018:	Fair Value		Unfunded Commitments		Redemption Frequency	Redemption Notice Period
	(in millions)
Southern Company	$	33	$	33	Not Applicable	Not Applicable
Alabama Power	$	33	$	33	Not Applicable	Not Applicable

224

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Private equity funds include a fund-of-funds that invests in high-quality private equity funds across several market sectors, funds that invest 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 10 years.

As of June 30, 2018, 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	$	45,806	$	46,481
Alabama Power	8,119		8,435
Georgia Power	10,294		10,499
Gulf Power	1,285		1,311
Mississippi Power	1,779		1,760
Southern Power	5,037		5,094
Southern Company Gas	5,823		5,957

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 Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Southern Power, and Southern Company Gas.

(E) 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 stock-based compensation plans. See Note 8 to the financial statements of Southern Company in Item 8 of the Form 10-K for information on stock-based compensation plans. The effect of stock-based compensation plans was determined using the treasury stock method. Shares used to compute diluted earnings per share were as follows:

	Three Months Ended June 30, 2018	Three Months Ended June 30, 2017	Six Months Ended June 30, 2018	Six Months Ended June 30, 2017
	(in millions)
As reported shares	1,014	998	1,012	996
Effect of stock-based compensation	—	7	5	7
Diluted shares	1,014	1,005	1,017	1,003

Stock-based compensation awards that were not included in the diluted earnings per share calculation because they were anti-dilutive totaled approximately 5.3 million shares for the three months ended June 30, 2018 and were immaterial for the three months ended June 30, 2017 and six months ended June 30, 2018 and 2017.

225

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Changes in Stockholders' Equity

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

	Number of Common Shares			Common Stockholders' Equity			Preferred and Preference Stock of Subsidiaries						Total Stockholders' Equity
	Issued	Treasury								Noncontrolling Interests(a)
	(in thousands)			(in millions)
Balance at December 31, 2017	1,008,532	(929	)	$	24,167		$	—		$	1,361		$	25,528
Consolidated net income attributable to Southern Company	—	—		784			—			—			784
Other comprehensive income	—	—		41			—			—			41
Stock issued	6,590	—		222			—			—			222
Stock-based compensation	—	—		48			—			—			48
Cash dividends on common stock	—	—		(1,194		)	—			—			(1,194		)
Contributions from noncontrolling interests	—	—		—			—			31			31
Distributions to noncontrolling interests	—	—		—			—			(42		)	(42		)
Net income attributable to noncontrolling interests	—	—		—			—			17			17
Sale of SPSH noncontrolling interests(b)	—	—		(407		)	—			1,690			1,283
Other	—	(57	)	(25		)	—			(1		)	(26		)
Balance at June 30, 2018	1,015,122	(986	)	$	23,636		$	—		$	3,056		$	26,692
Balance at December 31, 2016	991,213	(819	)	$	24,758		$	609		$	1,245		$	26,612
Consolidated net income attributable to Southern Company	—	—		(723		)	—			—			(723		)
Other comprehensive income (loss)	—	—		(11		)	—			—			(11		)
Stock issued	9,129	—		417			—			—			417
Stock-based compensation	—	—		72			—			—			72
Cash dividends on common stock	—	—		(1,134		)	—			—			(1,134		)
Preference stock redemption	—	—		—			(150		)	—			(150		)
Contributions from noncontrolling interests	—	—		—			—			71			71
Distributions to noncontrolling interests	—	—		—			—			(40		)	(40		)
Net income attributable to noncontrolling interests	—	—		—			—			16			16
Reclassification from redeemable noncontrolling interests	—	—		—			—			114			114
Other	—	(49	)	(7		)	3			1			(3		)
Balance at June 30, 2017	1,000,342	(868	)	$	23,372		$	462		$	1,407		$	25,241

(a) Primarily related to Southern Power Company and excludes redeemable noncontrolling interests. See Note 10 to the financial statements of Southern Power in Item 8 of the Form 10-K for additional information.

(b) See Note (J) under "Southern Power – Sale of Solar Facility Interests" for additional information.

226

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

(F) FINANCING

Bank Credit Arrangements

Bank credit arrangements provide liquidity support to the registrants' commercial paper borrowings and the traditional electric operating companies' revenue bonds. The amount of variable rate revenue bonds of the traditional electric operating companies outstanding requiring liquidity support as of June 30, 2018 was approximately $1.5 billion (comprised of approximately $854 million at Alabama Power, $550 million at Georgia Power, $82 million at Gulf Power, and $40 million at Mississippi Power). In addition, at June 30, 2018, the traditional electric operating companies had approximately $482 million (comprised of approximately $120 million at Alabama Power, $232 million at Georgia Power, $37 million at Gulf Power, and $93 million at Mississippi Power) of revenue bonds outstanding that were required to be remarketed within the next 12 months. Subsequent to June 30, 2018, approximately $43 million of these pollution control revenue bonds of Mississippi Power were purchased and held by Mississippi Power. 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, 2018:

	Expires												Executable Term Loans		Expires Within One Year
Company	2018		2019		2020		2022		Total		Unused		One Year		Term Out		No Term Out
	(in millions)
Southern Company(a)	$	—	$	—	$	—	$	2,000	$	2,000	$	1,999	$	—	$	—	$	—
Alabama Power	2		31		500		800		1,333		1,333		—		—		33
Georgia Power	—		—		—		1,750		1,750		1,736		—		—		—
Gulf Power	20		25		235		—		280		280		45		45		—
Mississippi Power	100		—		—		—		100		100		—		—		100
Southern Power Company(b)	—		—		—		750		750		728		—		—		—
Southern Company Gas(c)	—		—		—		1,900		1,900		1,895		—		—		—
Other	—		30		—		—		30		30		—		—		30
Southern Company Consolidated	$	122	$	86	$	735	$	7,200	$	8,143	$	8,101	$	45	$	45	$	163

(a) Represents the Southern Company parent entity.

(b) Does not include Southern Power's $120 million continuing letter of credit facility for standby letters of credit expiring in 2019, of which $23 million remains unused at June 30, 2018.

(c) Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $1.4 billion of these arrangements. Southern Company Gas' committed credit arrangements also include $500 million for which Nicor Gas is the borrower and which is restricted for working capital needs of Nicor Gas.

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.

DOE Loan Guarantee Borrowings

See Note 6 to the financial statements of Southern Company and Georgia Power under "DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K for additional information regarding Georgia Power's Loan Guarantee Agreement.

On July 27, 2017, Georgia Power entered into an amendment to the Loan Guarantee Agreement (LGA Amendment) in connection with the DOE's consent to Georgia Power's entry into the Vogtle Services Agreement and the related intellectual property licenses (IP Licenses). Under the terms of the Loan Guarantee Agreement, upon termination of

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the Vogtle 3 and 4 Agreement, further advances are conditioned upon the DOE's approval of any agreements entered into in replacement of the Vogtle 3 and 4 Agreement. Under the terms of the LGA Amendment, Georgia Power will not request any advances unless and until certain conditions are satisfied, including (i) receipt of the DOE's approval of the Bechtel Agreement (together with the Vogtle Services Agreement and the IP Licenses, the Replacement EPC Arrangements) and (ii) Georgia Power's entry into a further amendment to the Loan Guarantee Agreement with the DOE to reflect the Replacement EPC Arrangements.

In September 2017, the DOE issued a conditional commitment to Georgia Power for up to approximately $1.67 billion in additional guaranteed loans under the Loan Guarantee Agreement. In June 2018, the DOE approved a request by Georgia Power to extend the conditional commitment to September 30, 2018. Any further extension must be approved by the DOE. Final approval and issuance of these additional loan guarantees by the DOE cannot be assured and are subject to the negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions, including the Vogtle Owners' votes to continue construction.

As of June 30, 2018, Georgia Power had $2.6 billion of borrowings outstanding under the multi-advance term loan facility (FFB Credit Facility) among Georgia Power, the DOE, and the FFB.

Under the Loan Guarantee Agreement, Georgia Power is subject to customary borrower affirmative and negative covenants and events of default. In addition, Georgia Power is subject to project-related reporting requirements and other project-specific covenants and events of default.

In the event certain mandatory prepayment events (including any decision not to continue construction of Plant Vogtle Units 3 and 4) occur, the FFB's commitment to make further advances under the FFB Credit Facility will terminate and Georgia Power will be required to prepay the outstanding principal amount of all borrowings under the FFB Credit Facility over a period of five years (with level principal amortization). Among other things, these mandatory prepayment events include (i) the termination of the Vogtle Services Agreement or rejection of the Vogtle Services Agreement in bankruptcy if Georgia Power does not maintain access to intellectual property rights under the IP Licenses; (ii) a decision by Georgia Power not to continue construction of Plant Vogtle Units 3 and 4; (iii) cancellation of Plant Vogtle Units 3 and 4 by the Georgia PSC, or by Georgia Power if authorized by the Georgia PSC; and (iv) cost disallowances by the Georgia PSC that could have a material adverse effect on completion of Plant Vogtle Units 3 and 4 or Georgia Power's ability to repay the outstanding borrowings under the FFB Credit Facility. Under certain circumstances, insurance proceeds and any proceeds from an event of taking must be applied to immediately prepay outstanding borrowings under the FFB Credit Facility. In addition, if Georgia Power discontinues construction of Plant Vogtle Units 3 and 4, Georgia Power would be obligated to immediately repay a portion of the outstanding borrowings under the FFB Credit Facility to the extent such outstanding borrowings exceed 70% of Eligible Project Costs, net of the proceeds received by Georgia Power under the Guarantee Settlement Agreement. Georgia Power also may voluntarily prepay outstanding borrowings under the FFB Credit Facility. Under the FFB Credit Facility, any prepayment (whether mandatory or optional) will be made with a make-whole premium or discount, as applicable.

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Financing Activities

The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first six months of 2018:

Company	Senior Note Issuances		Senior Note Maturities, Redemptions, and Repurchases		Revenue Bond Maturities, Redemptions, and Repurchases		Other Long-Term Debt Redemptions and Maturities(*)
	(in millions)
Alabama Power	$	500	$	—	$	—	$	—
Georgia Power	—		1,000		398		104
Mississippi Power	600		—		—		900
Southern Power	—		350		—		420
Southern Company Gas	—		—		200		—
Other	—		—		—		7
Southern Company Consolidated	$	1,100	$	1,350	$	598	$	1,431

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

Southern Company

In March 2018, Southern Company entered into a $900 million short-term floating rate bank loan bearing interest based on one-month LIBOR. The proceeds were used for working capital and other general corporate purposes.

In April 2018, Southern Company borrowed $250 million pursuant to a short-term uncommitted bank credit arrangement, which bears interest at a rate agreed upon by Southern Company and the bank from time to time and is payable on no less than 30 days' demand by the bank.

In June 2018, Southern Company repaid at maturity two$100 million short-term floating rate bank term loans.

Alabama Power

In June 2018, Alabama Power issued $500 million aggregate principal amount of Series 2018A 4.30% Senior Notes due July 15, 2048. The proceeds were used to repay outstanding commercial paper and for general corporate purposes, including Alabama Power's continuous construction program.

Georgia Power

In January 2018, Georgia Power repaid its outstanding $150 million and $100 million floating rate bank loans due May 31, 2018 and October 26, 2018, respectively.

In March 2018, Georgia Power purchased and held $104.6 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 2013 and $173 million aggregate principal amount of Development Authority of Bartow County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Bowen Project), First Series 2009. Georgia Power may reoffer these bonds to the public at a later date.

In April 2018, Georgia Power purchased and held $55 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Fifth Series 1994. Georgia Power may reoffer these bonds to the public at a later date.

Also in April 2018, Georgia Power redeemed all $250 million aggregate principal amount of its Series 2008B 5.40% Senior Notes due June 1, 2018.

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In May 2018, through cash tender offers, Georgia Power repurchased and retired $89 million of the $250 million aggregate principal amount outstanding of its Series 2007A 5.65% Senior Notes due March 1, 2037, $326 million of the $500 million aggregate principal amount outstanding of its Series 2009A 5.95% Senior Notes due February 1, 2039, and $335 million of the $600 million aggregate principal amount outstanding of its Series 2010B 5.40% Senior Notes due June 1, 2040, for an aggregate purchase price, excluding accrued and unpaid interest, of $902 million.

In June 2018, Georgia Power purchased and held $65 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Second Series 2008. Georgia Power may reoffer these bonds to the public at a later date.

Mississippi Power

In March 2018, Mississippi Power issued $300 million aggregate principal amount of Series 2018A Floating Rate Senior Notes due March 27, 2020 bearing interest based on three-month LIBOR and $300 million aggregate principal amount of Series 2018B 3.95% Senior Notes due March 30, 2028. In March 2018, Mississippi Power also entered into a $300 million short-term floating rate bank loan bearing interest based on one-month LIBOR, of which $200 million was repaid in the second quarter 2018 and $50 million was repaid subsequent to June 30, 2018. Mississippi Power used the proceeds from these financings to repay a $900 million unsecured term loan.

Southern Power

In May 2018, Southern Power entered into two short-term floating rate bank loans, each for an aggregate principal amount of $100 million, which bear interest based on one-month LIBOR.

In the second quarter 2018, Southern Power used a portion of the proceeds from the sale of a 33% equity interest in SPSH to repay $420 million aggregate principal amount of long-term floating rate bank loans and $350 million aggregate principal amount of Series 2015A 1.50% Senior Notes due June 1, 2018. See Note (J) under "Southern Power – Sale of Solar Facility Interests" for additional information.

Southern Company Gas

On January 4, 2018, Southern Company Gas issued a floating rate promissory note to Southern Company in an aggregate principal amount of $100 million bearing interest based on one-month LIBOR. On March 28, 2018, Southern Company Gas repaid this promissory note.

In the second quarter 2018, Pivotal Utility Holdings caused $200 million aggregate principal amount of gas facility revenue bonds to be redeemed. Also in the second quarter 2018, Pivotal Utility Holdings, as borrower, and Southern Company Gas, as guarantor, entered into a $181 million short-term delayed draw floating rate bank term loan bearing interest based on one-month LIBOR, which Pivotal Utility Holdings used to repay the gas facility revenue bonds. Subsequent to June 30, 2018, Pivotal Utility Holdings repaid this short-term loan.

In May 2018, Southern Company Gas Capital borrowed $95 million pursuant to a short-term uncommitted bank credit arrangement, guaranteed by Southern Company Gas, bearing interest at a rate agreed upon by Southern Company Gas Capital and the bank from time to time and payable on no less than 30 days' demand by the bank. The proceeds of the loan were used to pay down short-term debt. Subsequent to June 30, 2018, Southern Company Gas Capital repaid this loan.

(G) RETIREMENT BENEFITS

On January 1, 2018, the qualified defined benefit pension plan of Southern Company Gas was merged into the qualified defined benefit pension plan of Southern Company. Following the plan merger, Southern Company has a qualified defined benefit, trusteed, pension plan covering substantially all employees, with the exception of employees at PowerSecure. The Southern Company qualified defined benefit pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). No mandatory

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contributions to the Southern Company qualified defined benefit pension plan are anticipated for the year ending December 31, 2018.

In addition, the Southern Company Gas non-qualified retirement plans were merged into the Southern Company non-qualified retirement plan (defined benefit and defined contribution). Following the non-qualified retirement plan mergers, Southern Company continues to provide certain non-qualified defined benefits for a select group of management and highly compensated employees, which are funded on a cash basis.

Furthermore, 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. Southern Company Gas also provides certain medical care and life insurance benefits for eligible retired employees through a postretirement benefit plan. Southern Company Gas has a separate unfunded supplemental retirement health care plan that provides medical care and life insurance benefits to employees of discontinued businesses.

As indicated in Note (A), the registrants adopted ASU 2017-07 as of January 1, 2018. ASU 2017-07 requires that an employer report the service cost component of net periodic benefit costs in the same line item or items as other compensation costs and requires the other components of net periodic benefit costs to be separately presented in the statements of income outside of income from operations. The presentation requirements of ASU 2017-07 have been applied retrospectively with the service cost component of net periodic benefit costs included in operations and maintenance and all other components of net periodic benefit costs included in other income (expense), net in the statements of income for the three and six months ended June 30, 2017.

With respect to the presentation requirements, the registrants have used the practical expedient provided by ASU 2017-07, which permits an employer to use the amounts disclosed in its retirement benefits footnote for prior comparative periods as the estimation basis for applying the retrospective presentation requirements to those periods. The amounts of the other components of net periodic benefit costs reclassified for the prior period are presented in the following tables.

See Note 2 to the financial statements of each registrant in Item 8 of the Form 10-K for additional information.

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Components of the net periodic benefit costs for the three and six months ended June 30, 2018 and 2017 are presented in the following tables.

Three Months Ended June 30, 2018	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power			Southern Power			Southern Company Gas
	(in millions)
Pension Plans
Service cost	$	89		$	20		$	21		$	4		$	4		$	2		$	8
Interest cost	116			25			35			5			5			2			9
Expected return on plan assets	(235		)	(53		)	(74		)	(10		)	(10		)	(2		)	(17		)
Amortization:
Prior service costs	1			1			1			—			—			—			—
Regulatory asset	—			—			—			—			—			—			4
Net (gain)/loss	54			13			17			3			2			—			3
Net periodic pension cost (income)	$	25		$	6		$	—		$	2		$	1		$	2		$	7
Postretirement Benefits
Service cost	$	6		$	2		$	1		$	1		$	1		$	—		$	—
Interest cost	18			4			7			—			1			—			3
Expected return on plan assets	(17		)	(7		)	(7		)	(1		)	(1		)	—			(2		)
Amortization:
Prior service costs	1			1			1			—			—			—			—
Regulatory asset	—			—			—			—			—			—			2
Net (gain)/loss	4			1			2			—			—			—			—
Net periodic postretirement benefit cost	$	12		$	1		$	4		$	—		$	1		$	—		$	3

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Six Months Ended June 30, 2018	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power			Southern Power			Southern Company Gas
	(in millions)
Pension Plans
Service cost	$	179		$	39		$	43		$	8		$	8		$	4		$	16
Interest cost	232			50			70			10			10			3			19
Expected return on plan assets	(471		)	(104		)	(148		)	(20		)	(20		)	(5		)	(35		)
Amortization:
Prior service costs	2			1			1			—			—			—			(1		)
Regulatory asset	—			—			—			—			—			—			7
Net (gain)/loss	107			27			34			5			5			1			6
Net periodic pension cost (income)	$	49		$	13		$	—		$	3		$	3		$	3		$	12
Postretirement Benefits
Service cost	$	12		$	3		$	3		$	1		$	1		$	—		$	1
Interest cost	37			8			14			1			2			—			5
Expected return on plan assets	(34		)	(13		)	(13		)	(1		)	(1		)	—			(4		)
Amortization:
Regulatory asset	3			2			1			—			—			—			3
Net (gain)/loss	7			1			4			—			—			—			—
Net periodic postretirement benefit cost	$	25		$	1		$	9		$	1		$	2		$	—		$	5

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Three Months Ended June 30, 2017(*)	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power			Southern Company Gas
	(in millions)
Pension Plans
Service cost	$	74		$	16		$	18		$	4		$	3		$	5
Interest cost	113			24			35			5			5			10
Expected return on plan assets	(225		)	(49		)	(70		)	(9		)	(10		)	(17		)
Amortization:
Prior service costs	3			—			1			—			1			(1		)
Net (gain)/loss	41			11			14			1			2			5
Net periodic pension cost (income)	$	6		$	2		$	(2	)	$	1		$	1		$	2
Postretirement Benefits
Service cost	$	6		$	2		$	1		$	1		$	1		$	—
Interest cost	20			4			8			—			1			2
Expected return on plan assets	(17		)	(8		)	(6		)	(1		)	(1		)	(1		)
Amortization:
Prior service costs	1			1			1			—			—			—
Net (gain)/loss	5			1			1			—			—			1
Net periodic postretirement benefit cost	$	15		$	—		$	5		$	—		$	1		$	2

(*) Excludes Southern Power since Southern Power did not participate in the qualified pension and postretirement benefit plans until December 2017.

Six Months Ended June 30, 2017(*)	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power			Southern Company Gas
	(in millions)
Pension Plans
Service cost	$	147		$	32		$	37		$	7		$	7		$	11
Interest cost	227			48			69			10			10			20
Expected return on plan assets	(449		)	(98		)	(141		)	(19		)	(20		)	(35		)
Amortization:
Prior service costs	6			1			2			—			1			(1		)
Net (gain)/loss	81			21			28			3			4			10
Net periodic pension cost (income)	$	12		$	4		$	(5	)	$	1		$	2		$	5
Postretirement Benefits
Service cost	$	12		$	3		$	3		$	1		$	1		$	1
Interest cost	40			9			15			1			2			5
Expected return on plan assets	(33		)	(14		)	(12		)	(1		)	(1		)	(3		)
Amortization:
Prior service costs	3			2			1			—			—			(1		)
Net (gain)/loss	7			1			3			—			—			2
Net periodic postretirement benefit cost	$	29		$	1		$	10		$	1		$	2		$	4

(*) Excludes Southern Power since Southern Power did not participate in the qualified pension and postretirement benefit plans until December 2017.

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(H) INCOME TAXES

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

Federal Tax Reform Legislation

Following the enactment of the Tax Reform Legislation, the SEC staff issued Staff Accounting Bulletin 118 – "Income Tax Accounting Implications of the Tax Cuts and Jobs Act" (SAB 118), which provides for a measurement period of up to one year from the enactment date to complete accounting under GAAP for the tax effects of the legislation. Due to the complex and comprehensive nature of the enacted tax law changes, and their application under GAAP, the registrants consider all amounts recorded in the financial statements as a result of the Tax Reform Legislation to be "provisional" as discussed in SAB 118 and subject to revision. Each of the registrants is awaiting additional guidance from industry and income tax authorities in order to finalize its accounting. The ultimate impact of the Tax Reform Legislation on deferred income tax assets and liabilities and the related regulatory assets and liabilities cannot be determined at this time. See Note (B) under "Regulatory Matters" for additional information.

Current and Deferred Income Taxes

Tax Credit Carryforwards

Southern Company had federal ITC and PTC carryforwards (primarily related to Southern Power) totaling $2.3 billion as of June 30, 2018 compared to $2.1 billion as of December 31, 2017.

The federal ITC and PTC carryforwards begin expiring in 2034 and 2032, respectively, but are expected to be fully utilized by 2021. The estimated tax credit utilization reflects the 2018 abandonment loss related to certain Kemper County energy facility expenditures as well as the projected taxable gains on the various sale transactions described in Note (J) and "Legal Entity Reorganizations" herein. The expected utilization of tax credit carryforwards could be further delayed by numerous factors, including the acquisition of additional renewable projects and increased generation at existing wind facilities. The ultimate outcome of these matters cannot be determined at this time.

Effective Tax Rate

Each registrant's effective tax rate for the six months ended June 30, 2018 varied significantly as compared to the corresponding period in 2017 due to the 14% lower 2018 federal tax rate resulting from the Tax Reform Legislation.

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 benefit rate was (3.2)% for the six months ended June 30, 2018 compared to a benefit rate of (28.6)% for the corresponding period in 2017. The effective tax rate increase was primarily due to the $3.1 billion pre-tax loss on the Kemper IGCC, net of the non-deductible AFUDC equity portion, recorded in 2017, partially offset by the $1.1 billion pre-tax loss related to Plant Vogtle Units 3 and 4 in 2018, the reduction in the federal corporate income tax rate and the benefit from the flowback of excess deferred income taxes as a result of the Tax Reform Legislation, as well as net state income tax benefits related to changes in state apportionment rates arising from the reorganization of Southern Power's legal entities as discussed further herein. See Note 3 to the financial statements of Southern Company under "Kemper County Energy Facility" in Item 8 of the Form 10-K and Note (B) under "Kemper County Energy Facility" for additional information regarding the Kemper IGCC and Note (B) under "Nuclear Construction" for additional information regarding Plant Vogtle Units 3 and 4. See Note (B) under "Regulatory Matters" for additional information on the flowback of excess deferred income taxes.

Southern Company recognizes PTCs when wind energy is generated and sold (using the prescribed KWH rate in applicable federal and state statutes), which may differ significantly from amounts computed on a quarterly basis using an overall estimated annual effective income tax rate. Southern Company uses this method of recognition

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since the amount of PTCs can be significantly impacted by wind generation. This method can significantly affect the effective income tax rate for the period depending on the amount of pretax income.

Alabama Power

Alabama Power's effective tax rate was 22.8% for the six months ended June 30, 2018 compared to 40.2% for the corresponding period in 2017. The effective tax rate decrease was primarily due to the reduction in the federal corporate income tax rate and the benefit from the flowback of excess deferred income taxes as a result of the Tax Reform Legislation. See Note (B) under "Regulatory Matters – Alabama Power" for additional information.

Georgia Power

Georgia Power's effective tax benefit rate was (53.5)% for the six months ended June 30, 2018 compared to an effective tax rate of 36.6% for the corresponding period in 2017. The effective tax rate decrease was primarily due to the $1.1 billion pre-tax loss related to the estimated probable loss on Plant Vogtle Units 3 and 4 recorded in 2018, partially offset by the reduction in the federal corporate income tax rate. See Note (B) under "Nuclear Construction" for additional information.

Gulf Power

Gulf Power's effective tax rate was 3.3% for the six months ended June 30, 2018 compared to 39.8% for the corresponding period in 2017. The effective tax rate decrease was primarily due to the reduction in the federal corporate income tax rate and the benefit from the flowback of excess deferred income taxes as a result of the Tax Reform Legislation. See Note (B) under "Regulatory Matters – Gulf Power" for additional information.

Mississippi Power

Mississippi Power's effective tax rate was 18.7% for the six months ended June 30, 2018 compared to a benefit rate of (30.5)% for the corresponding period in 2017. The effective tax rate increase was primarily due to the $3.1 billion pre-tax loss on the Kemper IGCC, net of the non-deductible AFUDC equity portion, recorded in 2017, partially offset by the reduction in the federal corporate income tax rate as a result of the Tax Reform Legislation. See Note (B) under "Regulatory Matters – Mississippi Power" for additional information.

Southern Power

Southern Power's effective tax benefit rate was (1,386.5)% for the six months ended June 30, 2018 compared to a benefit rate of (114.7)% for the corresponding period in 2017. The effective tax rate decrease was primarily due to lower earnings before income taxes resulting from a $119 million asset impairment charge related to the sale of Southern Power's equity interests in two natural gas-fired operating facilities, Plant Oleander and Plant Stanton Unit A (together, the Florida Plants) described in Note (J) under "Southern Power – Sale of Florida Plants," as well as the reduction in the federal corporate income tax rate and the net state income tax benefits related to certain changes in apportionment rates arising from the reorganization of Southern Power's legal entities as described below.

Southern Power recognizes PTCs when wind energy is generated and sold (using the prescribed KWH rate in applicable federal and state statutes), which may differ significantly from amounts computed on a quarterly basis using an overall estimated annual effective income tax rate. Southern Power uses this method of recognition since the amount of PTCs can be significantly impacted by wind generation. This method can significantly affect the effective income tax rate for the period depending on the amount of pretax income.

Southern Company Gas

Southern Company Gas' effective tax rate was 39.1% for the six months ended June 30, 2018 compared to 38.5% for the corresponding period in 2017. This increase was primarily related to income taxes recorded related to the sale of Pivotal Home Solutions, including the reduction in deferred tax expense as a result of treating the sale as an asset sale for tax purposes, partially offset by the reduction in the federal corporate income tax rate and the benefit from the flowback of excess deferred income taxes as a result of the Tax Reform Legislation. See Note (B) under

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"Regulatory Matters – Southern Company Gas" and Note (J) under "Southern Company Gas – Sale of Pivotal Home Solutions" for additional information.

Legal Entity Reorganizations

In March 2018, Southern Power substantially completed a legal entity reorganization of various direct and indirect subsidiaries that own and operate substantially all of its solar facilities, including certain subsidiaries owned in partnership with various third parties. The reorganization resulted in net state tax benefits related to certain changes in apportionment rates totaling approximately $50 million, which were recorded in the first quarter 2018. In April 2018, Southern Power completed the final stage of the reorganization resulting in additional net state tax benefits of approximately $4 million.

Southern Power is pursuing the sale of a noncontrolling interest in a portfolio of eight operating wind facilities through the use of third-party tax equity, which, if successful, is expected to close in the fourth quarter 2018. In the third quarter 2018, various direct and indirect subsidiaries of Southern Power that own and operate these wind facilities are expected to be reorganized under a new holding company in which the tax equity partner would invest. The reorganization is expected to result in estimated net state tax benefits totaling approximately $10 million related to certain changes in apportionment rates. The ultimate outcome of this matter cannot be determined at this time.

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.

The registrants had no unrecognized tax benefits as of June 30, 2018. 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 income tax returns through 2016, as well as the pre-Merger Southern Company Gas tax returns. Southern Company is a participant in the Compliance Assurance Process of the IRS. The audits for Southern Company's state income tax returns have either been concluded, or the statute of limitations has expired, for years prior to 2011.

(I) DERIVATIVES

Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas are exposed to market risks, including commodity price risk, interest rate risk, weather risk, and occasionally foreign currency exchange rate risk. To manage the volatility attributable to these exposures, each company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to each company's policies in areas such as counterparty exposure and risk management practices. Southern Company Gas' wholesale gas operations use various contracts in its commercial activities that generally meet the definition of derivatives. For the traditional electric operating companies, Southern Power, and Southern Company Gas' other businesses, 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 net basis. See Note (D) 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.

The registrants adopted ASU 2017-12 as of January 1, 2018. See Note (A) under "Recently Adopted Accounting Standards – Other" for additional information.

237

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Energy-Related Derivatives

Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas enter into energy-related derivatives to hedge exposures to electricity, natural gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the traditional electric operating companies and the natural gas distribution utilities have limited exposure to market volatility in energy-related commodity prices. Each of the traditional electric operating companies and certain of the natural gas distribution utilities of Southern Company Gas manage fuel-hedging programs, implemented per the guidelines of their respective state PSCs or other applicable state regulatory agencies, through the use of financial derivative contracts, which is expected to continue to mitigate price volatility. The Florida PSC approved a moratorium on Gulf Power's fuel-hedging program until January 1, 2021. The moratorium does not have an impact on the recovery of existing hedges entered into under the previously-approved hedging program. The traditional electric operating companies (with respect to wholesale generating capacity) and Southern Power have limited exposure to market volatility in energy-related commodity prices 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 capacity is used to sell electricity. Southern Company Gas retains exposure to price changes that can, in a volatile energy market, be material and can adversely affect its results of operations.

Southern Company Gas also enters into weather derivative contracts as economic hedges of operating margins in the event of warmer-than-normal weather. Exchange-traded options are carried at fair value, with changes reflected in operating revenues. Non-exchange-traded options are accounted for using the intrinsic value method. Changes in the intrinsic value for non-exchange-traded contracts are reflected in operating revenues.

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' and the natural gas distribution utilities' 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 and in the same income statement line item as the earnings effect of the hedged transactions.

• 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 and natural gas industries. 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.

238

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

At June 30, 2018, 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(*)	701	2022	2029
Alabama Power	82	2022	—
Georgia Power	174	2022	—
Gulf Power	13	2020	—
Mississippi Power	66	2022	—
Southern Power	14	2020	—
Southern Company Gas(*)	352	2020	2029

(*) Southern Company's and Southern Company Gas' derivative instruments include both long and short natural gas positions. A long position is a contract to purchase natural gas and a short position is a contract to sell natural gas. Southern Company Gas' volume represents the net of long natural gas positions of 3.9 billion mmBtu and short natural gas positions of 3.6 billion mmBtu as of June 30, 2018, which is also included in Southern Company's total volume.

In addition to the volumes discussed above, 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 17 million mmBtu for Southern Company, 3 million mmBtu for Alabama Power, 6 million mmBtu for Georgia Power, 1 million mmBtu for Gulf Power, 2 million mmBtu for Mississippi Power, and 5 million mmBtu for Southern Power.

For cash flow hedges of energy-related derivatives, the amounts expected to be reclassified from accumulated OCI to earnings for the next 12-month period ending June 30, 2019 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 derivatives' fair value gains or losses are recorded in OCI and are reclassified into earnings at the same time and presented on the same income statement line item as the earnings effect of the hedged transactions. 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 on the same income statement line item. 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.

239

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

At June 30, 2018, 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, 2018
	(in millions)					(in millions)
Fair Value Hedges of Existing Debt
Southern Company(*)	$	300	2.75%	3-month LIBOR + 0.92%	June 2020	$	(6	)
Southern Company(*)	1,500		2.35%	1-month LIBOR + 0.87%	July 2021	(57		)
Georgia Power	500		1.95%	3-month LIBOR + 0.76%	December 2018	(3		)
Georgia Power	200		4.25%	3-month LIBOR + 2.46%	December 2019	(3		)
Southern Company Consolidated	$	2,500				$	(69	)

(*) Represents the Southern Company parent entity.

The estimated pre-tax gains (losses) related to interest rate derivatives expected to be reclassified from accumulated OCI to interest expense for the next 12-month period ending June 30, 2019 are $(18) million for Southern Company and immaterial for all other registrants. Southern Company and certain subsidiaries have deferred gains and losses 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 derivatives' fair value gains or losses are recorded in OCI and are reclassified into earnings at the same time and on the same income statement line as the earnings effect of the hedged transactions, including foreign currency gains or losses arising from changes in the U.S. currency exchange rates. The derivatives employed as hedging instruments are structured to minimize ineffectiveness.

At June 30, 2018, 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, 2018
	(in millions)			(in millions)				(in millions)
Cash Flow Hedges of Existing Debt
Southern Power	$	677	2.95%	€	600	1.00%	June 2022	$	54
Southern Power	564		3.78%	500		1.85%	June 2026	55
Total	$	1,241		€	1,100			$	109

The estimated pre-tax gains (losses) related to foreign currency derivatives that will be reclassified from accumulated OCI to earnings for the next 12-month period ending June 30, 2019 are $(23) million for Southern Company and Southern Power.

240

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Derivative Financial Statement Presentation and Amounts

Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas enter into derivative contracts that 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. Southern Company and certain subsidiaries also utilize master netting agreements to mitigate exposure to counterparty credit risk. These agreements may contain provisions that permit netting across product lines and against cash collateral. The fair value amounts of derivative assets and liabilities on the balance sheet are presented net to the extent that there are netting arrangements or similar agreements with the counterparties.

241

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

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

	As of June 30, 2018						As of December 31, 2017
Derivative Category and Balance Sheet Location	Assets			Liabilities			Assets			Liabilities
	(in millions)						(in millions)
Southern Company
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	16		$	12		$	10		$	43
Other deferred charges and assets/Other deferred credits and liabilities	5			27			7			24
Assets held for sale, current/Liabilities held for sale, current	—			8			—			—
Assets held for sale/Liabilities held for sale	—			4			—			—
Total derivatives designated as hedging instruments for regulatory purposes	$	21		$	51		$	17		$	67
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Other current assets/Other current liabilities	$	2		$	3		$	3		$	14
Other deferred charges and assets/Other deferred credits and liabilities	1			1			—			—
Interest rate derivatives:
Other current assets/Other current liabilities	—			15			1			4
Other deferred charges and assets/Other deferred credits and liabilities	—			53			—			34
Foreign currency derivatives:
Other current assets/Other current liabilities	—			23			—			23
Other deferred charges and assets/Other deferred credits and liabilities	132			—			129			—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	135		$	95		$	133		$	75
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets/Other current liabilities	$	239		$	272		$	380		$	437
Other deferred charges and assets/Other deferred credits and liabilities	189			246			170			215
Total derivatives not designated as hedging instruments	$	428		$	518		$	550		$	652
Gross amounts recognized	$	584		$	664		$	700		$	794
Gross amounts offset(a)	$	(306	)	$	(489	)	$	(405	)	$	(598	)
Net amounts recognized in the Balance Sheets(b)	$	278		$	175		$	295		$	196

242

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

	As of June 30, 2018						As of December 31, 2017
Derivative Category and Balance Sheet Location	Assets			Liabilities			Assets			Liabilities
	(in millions)						(in millions)
Alabama Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	6		$	3		$	2		$	6
Other deferred charges and assets/Other deferred credits and liabilities	2			6			2			4
Total derivatives designated as hedging instruments for regulatory purposes	$	8		$	9		$	4		$	10
Gross amounts recognized	$	8		$	9		$	4		$	10
Gross amounts offset	$	(4	)	$	(4	)	$	(4	)	$	(4	)
Net amounts recognized in the Balance Sheets	$	4		$	5		$	—		$	6
Georgia Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	5		$	5		$	2		$	9
Other deferred charges and assets/Other deferred credits and liabilities	2			14			4			10
Total derivatives designated as hedging instruments for regulatory purposes	$	7		$	19		$	6		$	19
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current assets/Other current liabilities	$	—		$	5		$	—		$	4
Other deferred charges and assets/Other deferred credits and liabilities	—			1			—			1
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	—		$	6		$	—		$	5
Gross amounts recognized	$	7		$	25		$	6		$	24
Gross amounts offset	$	(7	)	$	(7	)	$	(6	)	$	(6	)
Net amounts recognized in the Balance Sheets	$	—		$	18		$	—		$	18
Gulf Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	—		$	8		$	—		$	14
Other deferred charges and assets/Other deferred credits and liabilities	—			4			—			7
Total derivatives designated as hedging instruments for regulatory purposes	$	—		$	12		$	—		$	21
Gross amounts recognized	$	—		$	12		$	—		$	21
Gross amounts offset	$	—		$	—		$	—		$	—
Net amounts recognized in the Balance Sheets	$	—		$	12		$	—		$	21

243

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

	As of June 30, 2018						As of December 31, 2017
Derivative Category and Balance Sheet Location	Assets			Liabilities			Assets			Liabilities
	(in millions)						(in millions)
Mississippi Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	2		$	3		$	1		$	6
Other deferred charges and assets/Other deferred credits and liabilities	1			6			1			3
Total derivatives designated as hedging instruments for regulatory purposes	$	3		$	9		$	2		$	9
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current assets/Other current liabilities	$	—		$	—		$	1		$	—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	—		$	—		$	1		$	—
Gross amounts recognized	$	3		$	9		$	3		$	9
Gross amounts offset	$	(2	)	$	(2	)	$	(2	)	$	(2	)
Net amounts recognized in the Balance Sheets	$	1		$	7		$	1		$	7
Southern Power
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Other current assets/Other current liabilities	$	2		$	2		$	3		$	11
Other deferred charges and assets/Other deferred credits and liabilities	1			1			—			—
Foreign currency derivatives:
Other current assets/Other current liabilities	—			23			—			23
Other deferred charges and assets/Other deferred credits and liabilities	132			—			129			—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	135		$	26		$	132		$	34
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets/Other current liabilities	$	—		$	—		$	—		$	2
Gross amounts recognized	$	135		$	26		$	132		$	36
Gross amounts offset	$	(2	)	$	(2	)	$	(3	)	$	(3	)
Net amounts recognized in the Balance Sheets	$	133		$	24		$	129		$	33

244

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

	As of June 30, 2018						As of December 31, 2017
Derivative Category and Balance Sheet Location	Assets			Liabilities			Assets			Liabilities
	(in millions)						(in millions)
Southern Company Gas
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Assets from risk management activities/Liabilities from risk management activities-current	$	3		$	1		$	5		$	8
Other deferred charges and assets/Other deferred credits and liabilities	—			1			—			—
Total derivatives designated as hedging instruments for regulatory purposes	$	3		$	2		$	5		$	8
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Assets from risk management activities/Liabilities from risk management activities-current	$	—		$	1		$	—		$	3
Derivatives not designated as hedging instruments
Energy-related derivatives:
Assets from risk management activities/Liabilities from risk management activities-current	$	239		$	272		$	379		$	434
Other deferred charges and assets/Other deferred credits and liabilities	189			246			170			215
Total derivatives not designated as hedging instruments	$	428		$	518		$	549		$	649
Gross amounts of recognized	$	431		$	521		$	554		$	660
Gross amounts offset(a)	$	(291	)	$	(474	)	$	(390	)	$	(583	)
Net amounts recognized in the Balance Sheets(b)	$	140		$	47		$	164		$	77

(a) Gross amounts offset include cash collateral held on deposit in broker margin accounts of $183 million and $193 million as of June 30, 2018 and December 31, 2017, respectively.

(b) Net amounts of derivative instruments outstanding exclude premium and intrinsic value associated with weather derivatives of $3 million and $11 million as of June 30, 2018 and December 31, 2017, respectively.

245

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

At June 30, 2018 and December 31, 2017, 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 in the Balance Sheet at June 30, 2018
Derivative Category and Balance Sheet Location	Southern Company(*)			Alabama Power			Georgia Power			Gulf Power			Mississippi Power			Southern Company Gas(*)
	(in millions)
Energy-related derivatives:
Other regulatory assets, current	$	(4	)	$	(1	)	$	(1	)	$	(8	)	$	(1	)	$	(1	)
Other regulatory assets, deferred	(20		)	(4		)	(11		)	(4		)	(5		)	—
Assets held for sale, current	(8		)	—			—			—			—			—
Assets held for sale	(4		)	—			—			—			—			—
Other regulatory liabilities, current	8			4			—			—			—			4
Total energy-related derivative gains (losses)	$	(28	)	$	(1	)	$	(12	)	$	(12	)	$	(6	)	$	3

(*) Fair value gains and losses recorded in regulatory assets and liabilities include cash collateral held on deposit in broker margin accounts of $2 million at June 30, 2018.

Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at December 31, 2017
Derivative Category and Balance Sheet Location	Southern Company(*)			Alabama Power			Georgia Power			Gulf Power			Mississippi Power			Southern Company Gas(*)
	(in millions)
Energy-related derivatives:
Other regulatory assets, current	$	(34	)	$	(4	)	$	(7	)	$	(14	)	$	(5	)	$	(4	)
Other regulatory assets, deferred	(18		)	(3		)	(6		)	(7		)	(2		)	—
Other regulatory liabilities, current	7			—			—			—			—			7
Other regulatory liabilities, deferred	1			1			—			—			—			—
Total energy-related derivative gains (losses)	$	(44	)	$	(6	)	$	(13	)	$	(21	)	$	(7	)	$	3

(*) Fair value gains and losses recorded in regulatory assets and liabilities include cash collateral held on deposit in broker margin accounts of $6 million at December 31, 2017.

246

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

For the three and six months ended June 30, 2018 and 2017, the pre-tax effects of cash flow hedge accounting on accumulated OCI were as follows:

Gain (Loss) Recognized in OCI on Derivative	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2018			2017			2018			2017
	(in millions)						(in millions)
Southern Company
Energy-related derivatives	$	—		$	(9	)	$	12		$	(20	)
Interest rate derivatives	—			(1		)	(2		)	(1		)
Foreign currency derivatives	(73		)	71			(21		)	67
Total	$	(73	)	$	61		$	(11	)	$	46
Southern Power
Energy-related derivatives	$	(1	)	$	(7	)	$	10		$	(15	)
Foreign currency derivatives	(73		)	71			(21		)	67
Total	$	(74	)	$	64		$	(11	)	$	52
Southern Company Gas
Energy-related derivatives	$	1		$	(2	)	$	2		$	(4	)

For the three and six months ended June 30, 2018 and 2017, the pre-tax effects of energy-related derivatives and interest rate derivatives designated as cash flow hedging instruments on accumulated OCI were immaterial for the other registrants.

For the three and six months ended June 30, 2017, there was no material ineffectiveness recorded in earnings for any registrant. Upon the adoption of ASU 2017-12, beginning in 2018, ineffectiveness was no longer separately measured and recorded in earnings. See Note (A) for additional information.

247

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

For the three and six months ended June 30, 2018 and 2017, the pre-tax effects of cash flow and fair value hedge accounting on income were as follows:

Location and Amount of Gain (Loss) Recognized in Income on Cash Flow and Fair Value Hedging Relationships	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2018			2017			2018			2017
	(in millions)						(in millions)
Southern Company
Depreciation and amortization	$	783		$	754		$	1,552		$	1,469
Gain (loss) on cash flow hedges(a)
Energy-related derivatives	1			(2		)	2			(6		)
Interest expense, net of amounts capitalized	(470		)	(424		)	(928		)	(840		)
Gain (loss) on cash flow hedges(a)
Interest rate derivatives	(6		)	(5		)	(11		)	(10		)
Foreign currency derivatives	(7		)	(5		)	(12		)	(12		)
Gain (loss) on fair value hedges(b)
Interest rate derivatives	(7		)	7			(31		)	(1		)
Other income (expense), net	78			52			138			98
Gain (loss) on cash flow hedges(a)(c)
Foreign currency derivatives	(73		)	79			(37		)	96
Cost of natural gas	228			232			949			951
Gain (loss) on cash flow hedges(a)
Energy-related derivatives	—			—			(2		)	—
Alabama Power
Interest expense, net of amounts capitalized	$	(80	)	$	(77	)	$	(158	)	$	(153	)
Gain (loss) on cash flow hedges(a)
Interest rate derivatives	(1		)	(2		)	(3		)	(3		)
Georgia Power
Interest expense, net of amounts capitalized	$	(102	)	$	(104	)	$	(208	)	$	(205	)
Gain (loss) on cash flow hedges(a)
Interest rate derivatives	(2		)	(1		)	(3		)	(3		)
Gain (loss) on fair value hedges(b)
Interest rate derivatives	2			—			(1		)	(1		)
Mississippi Power
Interest expense, net of amounts capitalized	$	(21	)	$	(17	)	$	(39	)	$	(37	)
Gain (loss) on cash flow hedges(a)
Interest rate derivatives	(1		)	—			(1		)	(1		)

248

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Location and Amount of Gain (Loss) Recognized in Income on Cash Flow and Fair Value Hedging Relationships	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2018			2017			2018			2017
	(in millions)						(in millions)
Southern Power
Depreciation and amortization	$	125		$	129		$	240		$	247
Gain (loss) on cash flow hedges(a)
Energy-related derivatives	1			(2		)	2			(6		)
Interest expense, net of amounts capitalized	(46		)	(48		)	(93		)	(97		)
Gain (loss) on cash flow hedges(a)
Foreign currency derivatives	(7		)	(5		)	(12		)	(12		)
Other income (expense), net	2			2			5			(2		)
Gain (loss) on cash flow hedges(a)(c)
Foreign currency derivatives	(73		)	79			(37		)	96
Southern Company Gas
Cost of natural gas	$	228		$	232		$	949		$	951
Gain (loss) on cash flow hedges(a)
Energy-related derivatives	—			—			(2		)	—

(a) Amounts reflect gains or losses on cash flow hedges that were reclassified from accumulated OCI into income.

(b) For fair value hedges presented above, generally changes in the fair value of the derivative contracts are equal to changes in the fair value of the underlying debt and have no material impact on income.

(c) The reclassification from accumulated OCI into other income (expense), net completely offsets currency gains and losses arising from changes in the U.S. currency exchange rates used to record the euro-denominated notes.

For the three and six months ended June 30, 2018 and 2017, the pre-tax effects of cash flow hedge accounting on income for interest rate derivatives were immaterial for Gulf Power and Southern Company Gas.

As of June 30, 2018 and December 31, 2017, the following amounts were recorded on the balance sheets related to cumulative basis adjustments for fair value hedges:

	Carrying Amount of the Hedged Item						Cumulative Amount of Fair Value Hedging Adjustment included in Carrying Amount of the Hedged Item
Balance Sheet Location of Hedged Items	As of June 30, 2018			As of December 31, 2017			As of June 30, 2018		As of December 31, 2017
	(in millions)						(in millions)
Southern Company
Securities due within one year	$	(497	)	$	(746	)	$	3	$	3
Long-term Debt	(2,528		)	(2,553		)	63		35
Georgia Power
Securities due within one year	$	(497	)	$	(746	)	$	3	$	3
Long-term Debt	(497		)	(498		)	3		1

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(UNAUDITED)

For the three and six months ended June 30, 2018 and 2017, the pre-tax effects of energy-related derivatives not designated as hedging instruments on the statements of income were as follows:

		Gain (Loss)
		Three Months Ended June 30,						Six Months Ended June 30,
Derivatives in Non-Designated Hedging Relationships	Statements of Income Location	2018			2017			2018			2017
		(in millions)						(in millions)
Southern Company
Energy-related derivatives:	Natural gas revenues(*)	$	(28	)	$	16		$	(43	)	$	65
	Cost of natural gas	2			(2		)	4			(4		)
Total derivatives in non-designated hedging relationships		$	(26	)	$	14		$	(39	)	$	61
Southern Company Gas
Energy-related derivatives:	Natural gas revenues(*)	$	(28	)	$	16		$	(43	)	$	65
	Cost of natural gas	2			(2		)	4			(4		)
Total derivatives in non-designated hedging relationships		$	(26	)	$	14		$	(39	)	$	61

(*) Excludes gains (losses) recorded in natural gas revenues associated with weather derivatives of $15 million for the six months ended June 30, 2017 and immaterial amounts for all other periods presented.

For the three and six months ended June 30, 2018 and 2017, the pre-tax effects of energy-related derivatives and interest rate derivatives not designated as hedging instruments were immaterial for the traditional electric operating companies and Southern Power.

Contingent Features

Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas 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, 2018, the registrants had no collateral posted with derivative counterparties to satisfy these arrangements.

For the registrants with interest rate derivatives at June 30, 2018, the fair value of interest rate derivative liabilities with contingent features and the maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, was immaterial. At June 30, 2018, the fair value of energy-related derivative liabilities with contingent features and the maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, were immaterial for all registrants. The maximum potential collateral requirements arising from the credit-risk-related contingent features for the traditional electric operating companies and Southern Power 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.

Alabama Power and Southern Power maintain accounts with certain regional transmission organizations to facilitate financial derivative transactions. Based on the value of the positions in these accounts and the associated margin requirements, Alabama Power and Southern Power may be required to post collateral. At June 30, 2018, cash collateral posted in these accounts was immaterial. Southern Company Gas maintains accounts with brokers or the clearing houses of certain exchanges to facilitate financial derivative transactions. Based on the value of the

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(UNAUDITED)

positions in these accounts and the associated margin requirements, Southern Company Gas may be required to deposit cash into these accounts. At June 30, 2018, cash collateral held on deposit in broker margin accounts was $183 million.

Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas are exposed to losses related to financial instruments in the event of counterparties' nonperformance. Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas 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, Southern Power, and Southern Company Gas 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', Southern Power's, and Southern Company Gas' exposure to counterparty credit risk. Southern Company Gas may require counterparties to pledge additional collateral when deemed necessary.

In addition, Southern Company Gas conducts credit evaluations and obtains appropriate internal approvals for the counterparty's line of credit before any transaction with the counterparty is executed. In most cases, the counterparty must have an investment grade rating, which includes a minimum long-term debt rating of Baa3 from Moody's and BBB- from S&P. Generally, Southern Company Gas requires credit enhancements by way of a guaranty, cash deposit, or letter of credit for transaction counterparties that do not have investment grade ratings.

Southern Company Gas also utilizes master netting agreements whenever possible to mitigate exposure to counterparty credit risk. When Southern Company Gas is engaged in more than one outstanding derivative transaction with the same counterparty and it also has a legally enforceable netting agreement with that counterparty, the "net" mark-to-market exposure represents the netting of the positive and negative exposures with that counterparty and a reasonable measure of Southern Company Gas' credit risk. Southern Company Gas also uses other netting agreements with certain counterparties with whom it conducts significant transactions. Master netting agreements enable Southern Company Gas to net certain assets and liabilities by counterparty. Southern Company Gas also nets across product lines and against cash collateral provided the master netting and cash collateral agreements include such provisions. Southern Company Gas may require counterparties to pledge additional collateral when deemed necessary.

Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas do not anticipate a material adverse effect on the financial statements as a result of counterparty nonperformance.

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(UNAUDITED)

(J) ACQUISITIONS AND DISPOSITIONS

Southern Company's Sale of Gulf Power

On May 20, 2018, Southern Company entered into a stock purchase agreement (Gulf Power SPA) with NextEra Energy and its wholly-owned subsidiary 700 Universe, LLC, which provides for the sale of all of the capital stock of Gulf Power for an aggregate cash purchase price of $5.75 billion (less the amount of indebtedness assumed at closing, which is currently estimated at approximately $1.4 billion), subject to (i) customary adjustments for indebtedness and working capital and (ii) reduction by the amount (if any) by which Gulf Power fails to meet a specified capital expenditure target.

The Gulf Power SPA contains customary representations, warranties, and covenants of Southern Company, 700 Universe, LLC, and NextEra Energy. These covenants include, among others, an obligation of Southern Company to cause Gulf Power to operate its business in the ordinary course until the sale is consummated and an obligation for each of the parties to use reasonable best efforts to obtain the governmental and regulatory approvals described below.

The completion of the sale is subject to the satisfaction or waiver of certain closing conditions, including, among others, (i) the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act (HSR Act), (ii) approval by the FERC and the Federal Communications Commission, (iii) the entry into certain ancillary agreements, including transmission-related agreements and a transition services agreement, among the parties and their affiliates, and (iv) other customary closing conditions.

The Gulf Power SPA may be terminated by either Southern Company or 700 Universe, LLC under certain circumstances, including if the sale is not consummated by June 28, 2019 (subject to extension to December 31, 2019, if all of the conditions to closing, other than the conditions related to obtaining regulatory approvals, have been satisfied). The Gulf Power SPA further provides that, upon the termination thereof, (i) under certain specified circumstances, 700 Universe, LLC will be required to pay Southern Company a termination fee of $100 million or $200 million (such amount depending on the specific circumstances of such termination) and (ii) upon certain other specified circumstances Southern Company will be required to pay 700 Universe, LLC a termination fee of $100 million.

The sale of Gulf Power is expected to occur in the first half of 2019. The assets and liabilities of Gulf Power are classified as assets held for sale and liabilities held for sale on Southern Company's balance sheet as of June 30, 2018. See "Assets Held for Sale" below for additional information. The ultimate outcome of this matter cannot be determined at this time.

Southern Power

See Note 11 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.

Acquisitions During the Six Months Ended June 30, 2018

During the six months ended June 30, 2018, one of Southern Power's wholly-owned subsidiaries acquired and completed construction of the Gaskell West 1 solar facility. Acquisition-related costs were expensed as incurred and were not material.

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(UNAUDITED)

Project Facility	Resource	Seller; Acquisition Date	Approximate Nameplate Capacity (MW)	Location	Southern Power Percentage Ownership		Actual COD	PPA Contract Period
Gaskell West 1	Solar	Recurrent Energy Development Holdings, LLC January 26, 2018	20	Kern County, CA	100% of Class B	(*)	March 2018	20 years

(*) Southern Power owns 100% of the class B membership interests under a tax equity partnership agreement.

The Gaskell West 1 facility did not have operating revenues or activities prior to completion of construction and the assets being placed in service during March 2018.

Construction Projects Completed and in Progress

During the six months ended June 30, 2018, Southern Power started or continued construction of the projects set forth in the table below. Total aggregate construction costs, excluding the acquisition costs, are expected to be between $520 million and $590 million for the Cactus Flats, Mankato, and Wild Horse Mountain facilities. At June 30, 2018, construction costs included in CWIP related to these projects totaled $353 million. The ultimate outcome of these matters cannot be determined at this time.

Project Facility	Resource	Approximate Nameplate Capacity (MW)	Location	Actual/Expected COD	PPA Contract Period
Projects Under Construction as of June 30, 2018
Cactus Flats(a)	Wind	148	Concho County, TX	July 2018	12-15 years
Mankato	Natural Gas	345	Mankato, MN	First half 2019	20 years
Wild Horse Mountain(b)	Wind	100	Pushmataha County, OK	Fourth quarter 2019	20 years

(a) In July 2017, Southern Power purchased 100% of the Cactus Flats facility and commenced construction. Subsequent to June 30, 2018, the facility was placed in service and Southern Power expects to close on a tax equity partnership agreement, which would result in Southern Power owning 100% of the class B membership interests.

(b) In May 2018, Southern Power purchased 100% of the Wild Horse Mountain facility and commenced construction. Southern Power may enter into a tax equity partnership agreement, in which case it would then own 100% of the class B membership interests.

Development Projects

During 2017, as part of its renewable development strategy, Southern Power purchased wind turbine equipment from Siemens Gamesa Renewable Energy Inc. and Vestas-American Wind Technology, Inc. to be used for various development and construction projects. Any wind projects reaching commercial operation by 2021 are expected to qualify for 80% PTCs.

During 2016, Southern Power entered into a joint development agreement with Renewable Energy Systems Americas, Inc. to develop and construct wind projects. In addition, in 2016, Southern Power purchased wind turbine equipment from Siemens Wind Power, Inc. and Vestas-American Wind Technology, Inc. to be used for construction of the facilities. Any wind projects reaching commercial operation by 2020 are expected to qualify for 100% PTCs.

In response to the previously disclosed decrease of planned expenditures for plant acquisitions and placeholder growth, Southern Power continues to refine the deployment of wind turbine equipment to projects and the amount of MW capacity to be constructed. While the expectation is that the majority of the equipment will be deployed in a manner to qualify for the 100% and 80% PTCs, Southern Power may consider other strategies, such as selling equipment or interests in projects.

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

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(UNAUDITED)

Sale of Solar Facility Interests

In May 2018, Southern Power sold a 33% equity interest in SPSH, a newly-formed limited partnership indirectly owning substantially all of Southern Power's solar facilities, to Global Atlantic Financial Group Limited (Global Atlantic) for approximately $1.2 billion, subject to customary working capital adjustments. The proceeds were used to repay $770 million of existing indebtedness, to return capital of $250 million to Southern Company, and for other general corporate purposes, including working capital. Since Southern Power retains control of the limited partnership through its wholly-owned general partner, the sale was recorded as an equity transaction and Southern Power will continue to consolidate the results of SPSH. On the date of the transaction, the noncontrolling interest was increased by $511 million to reflect 33% of the carrying value of the partnership. This difference, partially offset by the tax impact and other related transaction charges, also resulted in a $407 million decrease to Southern Power's common stockholder's equity.

Sale of Florida Plants

In May 2018, Southern Power entered into an equity interest purchase agreement with NextEra Energy to sell all of its equity interests in the Florida Plants, for an aggregate purchase price of $195 million, subject to customary working capital and timing adjustments.

The sale is subject to certain closing and timing conditions and approvals, including, but not limited to, the expiration or termination of the waiting period under the HSR Act and approval by the FERC. The ultimate purchase price will decrease $110,000 per day for each day after December 31, 2018 through the closing of the transaction. Conversely, the ultimate purchase price will increase $110,000 per day for each day the closing occurs prior to December 31, 2018. The transaction is currently expected to occur in the first half of 2019. As a result of this pending transaction, Southern Power recorded an asset impairment charge of approximately $119 million ($89 million after tax) in the second quarter 2018. The assets and liabilities of the Florida Plants are classified as assets held for sale and liabilities held for sale on Southern Company's and Southern Power's balance sheets as of June 30, 2018. See "Assets Held for Sale" below for additional information. The ultimate outcome of this matter cannot be determined at this time.

Assets Subject to Lien

Under the terms of the PPA and the expansion PPA for the Mankato project, approximately $475 million of assets, primarily related to property, plant, and equipment, are subject to lien at June 30, 2018.

Southern Company Gas

Sale of Pivotal Home Solutions

On June 4, 2018, Southern Company Gas completed the stock sale of Pivotal Home Solutions to American Water Enterprises LLC for a total cash purchase price of $358 million and an additional $6 million for working capital. This disposition resulted in a net loss of $76 million, which included $40 million of income tax expense. In contemplation of the transaction, a goodwill impairment charge of $42 million was recorded during the first quarter 2018. The after-tax loss included income tax expense on goodwill not deductible for tax purposes and for which a deferred tax liability had not been recorded previously. Additionally, this disposition is subject to a final working capital adjustment that may impact the cash proceeds from disposition, but not the loss recorded. Southern Company Gas and American Water Enterprises LLC entered into a transition services agreement whereby Southern Company Gas will provide certain administrative and operational services through no later than February 3, 2019.

Sale of Elizabethtown Gas and Elkton Gas

On July 1, 2018, a Southern Company Gas subsidiary, Pivotal Utility Holdings, completed the sales of the assets of two of its natural gas distribution utilities, Elizabethtown Gas and Elkton Gas, to South Jersey Industries, Inc. for a total cash purchase price of $1.7 billion and an additional $40 million for working capital. This disposition resulted in an estimated pre-tax gain of approximately $235 million and an after-tax gain of approximately $12 million,

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(UNAUDITED)

which will be recorded in the third quarter 2018. The after-tax gain included income tax expense on goodwill not deductible for tax purposes and for which a deferred tax liability had not been recorded previously. Additionally, this disposition is subject to a final working capital adjustment that may impact the cash proceeds from disposition, but not the gain that will be recorded in the third quarter 2018. Southern Company Gas and South Jersey Industries, Inc. entered into transition services agreements whereby Southern Company Gas will provide certain administrative and operational services through no later than January 31, 2020. The assets and liabilities of Elizabethtown Gas and Elkton Gas are classified as assets held for sale and liabilities held for sale on Southern Company's and Southern Company Gas' balance sheets at June 30, 2018. See "Assets Held for Sale" below for additional information.

Sale of Florida City Gas

On July 29, 2018, Southern Company Gas and its wholly-owned direct subsidiary, NUI Corporation, completed the stock sale of Pivotal Utility Holdings, which primarily consisted of Florida City Gas, to NextEra Energyfor a total cash purchase price of$530 million (less $3 million of indebtedness assumed at closing for customer deposits) and an additional $60 million for cash and other working capital. This disposition resulted in an estimated pre-tax gain of approximately $126 million and an after-tax gain of approximately $4 million, which will be recorded in the third quarter 2018. The after-tax gain included income tax expense on goodwill not deductible for tax purposes and for which a deferred tax liability had not been recorded previously. Additionally, this disposition is subject to a final working capital adjustment that may impact the cash proceeds from disposition, but not the gain that will be recorded in the third quarter 2018. Southern Company Gas and NextEra Energy entered into a transition services agreement whereby Southern Company Gas will provide certain administrative and operational services through no later than July 29, 2020. The assets and liabilities of Florida City Gas are classified as assets held for sale and liabilities held for sale on Southern Company's and Southern Company Gas' balance sheets at June 30, 2018. See "Assets Held for Sale" below for additional information.

Assets Held for Sale

As discussed above, Southern Company, Southern Power, and Southern Company Gas each have assets and liabilities held for sale on their balance sheets at June 30, 2018. Assets and liabilities held for sale have been classified separately on each company's balance sheet at the lower of carrying value or fair value less costs to sell at the time the criteria for held-for-sale classification were met. For assets and liabilities held for sale recorded at fair value on a nonrecurring basis, the fair value of assets held for sale is based primarily on unobservable inputs (Level 3), which includes the agreed upon sales prices in executed sales agreements.

Upon classification as held for sale in May 2018, Southern Power ceased recognizing depreciation on the Florida Plants' property, plant, and equipment to be sold. Since the depreciation of the assets to be sold in the Gulf Power transaction continues to be reflected in customer rates and will be reflected in the carryover basis of the assets when sold, Southern Company will continue to record depreciation on those assets through the date the transaction closes. Likewise, since the depreciation of the assets sold in the Elizabethtown Gas, Elkton Gas, and Florida City Gas transactions continued to be reflected in customer rates and was reflected in the carryover basis of the assets when sold, Southern Company Gas continued to record depreciation on those assets through the respective date that each transaction closed.

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(UNAUDITED)

The following table provides each company's major classes of assets and liabilities classified as held for sale at June 30, 2018:

	Southern Company		Southern Power		Southern Company Gas
	(in millions)
Assets Held for Sale:
Current assets	$	487	$	17	$	81
Total property, plant, and equipment	5,462		168		1,408
Goodwill and other intangible assets	668		—		668
Other non-current assets	705		15		141
Total Assets Held for Sale	$	7,322	$	200	$	2,298
Liabilities Held for Sale:
Current liabilities	$	354	$	2	$	61
Long-term debt	1,285		—		—
Accumulated deferred income taxes	566		—		26
Other non-current liabilities	1,334		—		325
Total Liabilities Held for Sale	$	3,539	$	2	$	412

Southern Company, Southern Power, and Southern Company Gas each concluded that the sale of these assets, both individually and combined, did not represent a strategic shift in operations that has, or is expected to have, a major effect on its operations and financial results; therefore, none of these assets held for sale have been classified as discontinued operations for any of the periods presented.

Gulf Power and the Florida Plants represent individually significant components of Southern Company and Southern Power, respectively; therefore, pre-tax profit for these components for the three and six months ended June 30, 2018 and 2017 is presented below:

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2018		2017		2018		2017
	(in millions)				(in millions)
Earnings before income taxes:
Gulf Power	$	31	$	61	$	87	$	95
Southern Power's Florida Plants(*)	$	14	$	11	$	24	$	20

(*) Excludes any allocation of interest from Southern Power's corporate debt.

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(UNAUDITED)

(K) VARIABLE INTEREST ENTITY AND EQUITY METHOD INVESTMENTS

Southern Power

In May 2018, Southern Power sold a 33% equity interest in SPSH to Global Atlantic. See Note (J) under "Southern Power" for additional information. A wholly-owned subsidiary of Southern Power is the general partner and holds a 1% ownership interest in SPSH and another wholly-owned subsidiary of Southern Power owns the remaining 66% ownership in SPSH. SPSH is a variable interest entity (VIE) because the arrangement is structured as a limited partnership and the 33% limited partner does not have substantive kick-out rights against the general partner. Southern Power previously consolidated SPSH and will continue to do so as the primary beneficiary of the VIE because it controls the most significant activities of the partnership, including operating and maintaining its assets.

At June 30, 2018, SPSH had total assets of $6.5 billion, total liabilities of $0.1 billion, and noncontrolling interests related to other partners' interests of $1.2 billion. Cash distributions from SPSH are allocated 67% to Southern Power and 33% to Global Atlantic in accordance with their membership interests and the limited partnership agreement.

Transfers and sales of the assets in the VIE are subject to limited partner consent and the liabilities do not have recourse to the general credit of Southern Power. Liabilities consist of customary working capital items and do not include any long-term debt.

Southern Company Gas

See Note 4 to the financial statements of Southern Company Gas in Item 8 of the Form 10-K for additional information.

Equity Method Investments

The carrying amounts of Southern Company Gas' equity method investments as of June 30, 2018 and December 31, 2017 and related income from those investments for the three and six-month periods ended June 30, 2018 and June 30, 2017 were as follows:

Investment Balance	June 30, 2018		December 31, 2017
	(in millions)
SNG	$	1,258	$	1,262
Atlantic Coast Pipeline	56		41
PennEast Pipeline	67		57
Triton	42		42
Pivotal JAX LNG, LLC	52		44
Horizon Pipeline	31		30
Other	1		1
Total	$	1,507	$	1,477

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(UNAUDITED)

Earnings from Equity Method Investments	Three Months Ended June 30, 2018		Three Months Ended June 30, 2017		Six Months Ended June 30, 2018		Six Months Ended June 30, 2017
	(in millions)
SNG	$	27	$	24	$	66	$	58
PennEast Pipeline	1		1		2		4
Atlantic Coast Pipeline	1		2		3		3
Triton	1		2		2		2
Horizon Pipeline	1		—		1		1
Total	$	31	$	29	$	74	$	68

Southern Natural Gas

Selected financial information of SNG for the three and six months ended June 30, 2018 and June 30, 2017 is as follows:

Income Statement Information	Three Months Ended June 30, 2018		Three Months Ended June 30, 2017		Six Months Ended June 30, 2018		Six Months Ended June 30, 2017
	(in millions)
Revenues	$	146	$	143	$	306	$	298
Operating income	$	60	$	63	$	159	$	147
Net income	$	54	$	48	$	132	$	114

(L) SEGMENT AND RELATED INFORMATION

Southern Company

The primary businesses of the Southern Company system are electricity sales by the traditional electric operating companies and Southern Power and the distribution of natural gas by Southern Company Gas. 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 develops, constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through its natural gas distribution utilities in four states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations. Through June 30, 2018, Southern Company Gas had seven natural gas distribution utilities in seven states. Subsequent to June 30, 2018, Southern Company Gas completed sales of three of its natural gas distribution utilities. See Note (J) under "Southern Company Gas" for additional information.

Southern Company's reportable business segments are the sale of electricity by the four traditional electric operating companies, the sale of electricity in the competitive wholesale market by Southern Power, and the sale of natural gas and other complementary products and services by Southern Company Gas. Revenues from sales by Southern Power to the traditional electric operating companies were $109 million and $192 million for the three and six months ended June 30, 2018, respectively, and $90 million and $190 million for the three and six months ended June 30, 2017, respectively. Revenues from sales of natural gas from Southern Company Gas to the traditional electric operating companies were $8 million for both the three and six months ended June 30, 2018 and $10 million for both the three and six months ended June 30, 2017. Revenues from sales of natural gas from Southern Company Gas to Southern Power were $22 million and $58 million for the three and six months ended June 30, 2018, respectively, and $33 million and $56 million for the three and six months ended June 30, 2017, respectively. The "All Other" column includes the Southern Company parent entity, which does not allocate operating expenses to

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business segments. Also, this category includes segments below the quantitative threshold for separate disclosure. These segments include providing energy technologies and services to electric utilities and large industrial, commercial, institutional, and municipal customers; 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, 2018 and 2017 was as follows:

	Electric Utilities
	Traditional Electric Operating Companies			Southern Power		Eliminations			Total			Southern Company Gas			All Other			Eliminations			Consolidated
	(in millions)
Three Months Ended June 30, 2018:
Operating revenues	$	4,124		$	555	$	(114	)	$	4,565		$	730		$	381		$	(49	)	$	5,627
Segment net income (loss)(a)(b)(c)	(48		)	22		—			(26		)	(31		)	(100		)	3			(154		)
Six Months Ended June 30, 2018:
Operating revenues	$	8,104		$	1,064	$	(220	)	$	8,948		$	2,369		$	782		$	(100	)	$	11,999
Segment net income (loss)(a)(b)(c)(d)	563			143		—			706			248			(174		)	4			784
At June 30, 2018:
Goodwill	$	—		$	2	$	—		$	2		$	5,015		$	298		$	—		$	5,315
Total assets	73,634			15,428		(313		)	88,749			22,112			3,707			(1,791		)	112,777
Three Months Ended June 30, 2017:
Operating revenues	$	4,157		$	529	$	(101	)	$	4,585		$	716		$	166		$	(37	)	$	5,430
Segment net income (loss)(a)(b)	(1,442		)	82		—			(1,360		)	49			(68		)	(2		)	(1,381		)
Six Months Ended June 30, 2017:
Operating revenues	$	7,943		$	979	$	(206	)	$	8,716		$	2,276		$	289		$	(79	)	$	11,202
Segment net income (loss)(a)(b)(e)	(1,010		)	151		—			(859		)	288			(152		)	—			(723		)
At December 31, 2017:
Goodwill	$	—		$	2	$	—		$	2		$	5,967		$	299		$	—		$	6,268
Total assets	72,204			15,206		(325		)	87,085			22,987			2,552			(1,619		)	111,005

(a) Attributable to Southern Company.

(b) Segment net income (loss) for the traditional electric operating companies includes pre-tax charges for estimated losses on plants under construction of $1.1 billion ($0.8 billion after tax) and $3.0 billion ($2.1 billion after tax) for the three months ended June 30, 2018 and 2017, respectively, and $1.1 billion ($0.8 billion after tax) and $3.1 billion ($2.2 billion after tax) for the six months ended June 30, 2018 and 2017, respectively. See Note 3 to the financial statements of Southern Company under "Kemper County Energy Facility" in Item 8 of the Form 10-K and Note (B) under "Nuclear Construction" and "Kemper County Energy Facility" for additional information.

(c) Segment net income (loss) for Southern Power includes a pre-tax impairment charge of $119 million ($89 million after tax) for the three and six months ended June 30, 2018 related to the pending sale of Southern Power's Florida Plants. See Note (J) under "Southern Power – Sale of Florida Plants" for additional information.

(d) Segment net income (loss) for Southern Company Gas includes a goodwill impairment charge of $42 million for the six months ended June 30, 2018 related to the sale of Pivotal Home Solutions. See Note (J) under "Southern Company Gas – Sale of Pivotal Home Solutions" for additional information.

(e) Segment net income (loss) for the traditional electric operating companies includes a pre-tax charge for the write-down of Gulf Power's ownership of Plant Scherer Unit 3 of $33 million ($20 million after tax) for the six months ended June 30, 2017. See Note 3 to the financial statements of Southern Company under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" in Item 8 of the Form 10-K for additional information.

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(UNAUDITED)

Products and Services

	Electric Utilities' Revenues
Period	Retail		Wholesale		Other		Total
	(in millions)
Three Months Ended June 30, 2018	$	3,740	$	611	$	214	$	4,565
Three Months Ended June 30, 2017	3,777		618		190		4,585
Six Months Ended June 30, 2018	$	7,308	$	1,230	$	410	$	8,948
Six Months Ended June 30, 2017	7,171		1,149		396		8,716

	Southern Company Gas' Revenues
Period	Gas Distribution Operations		Gas Marketing Services		Other			Total
	(in millions)
Three Months Ended June 30, 2018	$	638	$	89	$	3		$	730
Three Months Ended June 30, 2017	557		166		(7		)	716
Six Months Ended June 30, 2018	$	1,838	$	359	$	172		$	2,369
Six Months Ended June 30, 2017	1,689		454		133			2,276

Southern Company Gas

Southern Company Gas manages its business through four reportable segments – gas distribution operations, gas marketing services, wholesale gas services, and gas midstream operations. The non-reportable segments are combined and presented as all other.

Gas distribution operations is the largest component of Southern Company Gas' business and includes natural gas local distribution utilities that construct, manage, and maintain intrastate natural gas pipelines and gas distribution facilities in seven states. Subsequent to June 30, 2018, Southern Company Gas sold three of its natural gas distribution utilities, Elizabethtown Gas, Elkton Gas, and Florida City Gas. See Note (J) under "Southern Company Gas" for additional information.

Gas marketing services includes natural gas marketing to end-use customers primarily in Georgia and Illinois. On June 4, 2018, Southern Company Gas sold Pivotal Home Solutions. See Note (J) under "Southern Company Gas" for additional information.

Wholesale gas services provides natural gas asset management and/or related logistics services for each of Southern Company Gas' utilities except Nicor Gas as well as for non-affiliated companies. Additionally, wholesale gas services engages in natural gas storage and gas pipeline arbitrage and related activities.

Gas midstream operations primarily consists of Southern Company Gas' pipeline investments, with storage and fuel operations also aggregated into this segment.

The all other column includes segments below the quantitative threshold for separate disclosure, including the subsidiaries that fall below the quantitative threshold for separate disclosure.

260

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Business segment financial data for the three and six months ended June 30, 2018 and 2017 was as follows:

	Gas Distribution Operations(a)		Gas Marketing Services(b)(c)			Wholesale Gas Services(d)			Gas Midstream Operations		Total			All Other			Eliminations			Consolidated
	(in millions)
Three Months Ended June 30, 2018:
Operating revenues	$	643	$	89		$	(16	)	$	18	$	734		$	1		$	(5	)	$	730
Segment net income	68		(76		)	(21		)	14		(15		)	(16		)	—			(31		)
Six Months Ended June 30, 2018:
Operating revenues	1,856		359			150			40		2,405			2			(38		)	2,369
Segment net income	216		(63		)	83			38		274			(26		)	—			248
Total assets at June 30, 2018:	18,654		1,610			818			2,269		23,351			11,544			(12,783		)	22,112
Three Months Ended June 30, 2017:
Operating revenues	$	603	$	166		$	(12	)	$	12	$	769		$	3		$	(56	)	$	716
Segment net income	54		4			(17		)	9		50			(1		)	—			49
Six Months Ended June 30, 2017:
Operating revenues	1,783		454			119			37		2,393			5			(122		)	2,276
Segment net income	171		35			51			25		282			6			—			288
Total assets at December 31, 2017:	19,358		2,147			1,096			2,241		24,842			12,184			(14,039		)	22,987

(a) Operating revenues for the three gas distribution operations dispositions were $70 million and $66 million for the three months ended June 30, 2018 and 2017, respectively, and $237 million and $224 million for the six months ended June 30, 2018 and 2017, respectively. See Note (J) under "Southern Company Gas" for additional information.

(b) Operating revenues for the gas marketing services disposition were $24 million and $32 million for the three months ended June 30, 2018 and 2017, respectively, and $55 million and $63 million for the six months ended June 30, 2018 and 2017, respectively. See Note (J) under "Southern Company Gas" for additional information.

(c) Segment net income for gas marketing services includes a loss on disposition of $36 million for the three and six months ended June 30, 2018 and a goodwill impairment charge of $42 million for the six months ended June 30, 2018 recorded in contemplation of the sale of Pivotal Home Solutions. See Note (J) under "Southern Company Gas" for additional information.

(d) The revenues for wholesale gas services are netted with costs associated with its energy and risk management activities. A reconciliation of operating revenues and intercompany revenues is shown in the following table.

	Third Party Gross Revenues		Intercompany Revenues		Total Gross Revenues		Less Gross Gas Costs		Operating Revenues
	(in millions)
Three Months Ended June 30, 2018	$	1,336	$	102	$	1,438	$	1,454	$	(16	)
Three Months Ended June 30, 2017	1,531		123		1,654		1,666		(12		)
Six Months Ended June 30, 2018	$	3,274	$	269	$	3,543	$	3,393	$	150
Six Months Ended June 30, 2017	3,370		259		3,629		3,510		119

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PART II — OTHER INFORMATION

Item 1. Legal Proceedings.

See the Notes to the Condensed Financial Statements herein for information regarding certain legal and administrative proceedings in which the registrants are involved.

Item 1A. Risk Factors.

See RISK FACTORS in Item 1A of the Form 10-K for a discussion of the risk factors of the registrants. Except as described below, there have been no material changes to these risk factors from those previously disclosed in the Form 10-K.

Georgia Power may incur additional costs or delays in the construction of Plant Vogtle Units 3 or 4 and may not be able to recover its investments, which could have a material impact on the financial statements of Southern Company and Georgia Power.

Background

In 2009, the Georgia PSC certified construction of Plant Vogtle Units 3 and 4. In 2012, the NRC issued the related combined construction and operating licenses, which allowed full construction of the two AP1000 nuclear units (with electric generating capacity of approximately 1,100 MWs each) and related facilities to begin. Until March 2017, construction on Plant Vogtle Units 3 and 4 continued under the Vogtle 3 and 4 Agreement, which was a substantially fixed price agreement. In March 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code.

In connection with the EPC Contractor's bankruptcy filing, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into the Interim Assessment Agreement with the EPC Contractor to allow construction to continue. The Interim Assessment Agreement expired in July 2017 when Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the EPC Contractor entered into the Vogtle Services Agreement. Under the Vogtle Services Agreement, Westinghouse provides facility design and engineering services, procurement and technical support, and staff augmentation on a time and materials cost basis.

In October 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into a construction completion agreement with Bechtel, whereby Bechtel will serve as the primary contractor for the remaining construction activities for Plant Vogtle Units 3 and 4 (Bechtel Agreement). The Bechtel Agreement is a cost reimbursable plus fee arrangement, whereby Bechtel is reimbursed for actual costs plus a base fee and an at-risk fee, which is subject to adjustment based on Bechtel's performance against cost and schedule targets.

In December 2017, the Georgia PSC approved Georgia Power's seventeenth VCM report, which included a recommendation to continue construction of Plant Vogtle Units 3 and 4, with Southern Nuclear serving as project manager and Bechtel serving as the primary construction contractor.

262

Cost and Schedule

In preparation for its nineteenth VCM filing, Georgia Power requested Southern Nuclear to perform a full cost reforecast for the project. Georgia Power's approximate proportionate share of the remaining estimated capital cost to complete Plant Vogtle Units 3 and 4 by the expected in-service dates of November 2021 and November 2022, respectively, is as follows:

	(in billions)
Base project capital cost forecast(a)(b)	$	8.0
Construction contingency estimate	0.4
Total project capital cost forecast(a)(b)	8.4
Net investment as of June 30, 2018(b)	(4.0		)
Remaining estimate to complete(a)	$	4.4

(a) Excludes financing costs expected to be capitalized through AFUDC of approximately $350 million.

(b) Net of $1.7 billion received from Toshiba in 2017 under the Guarantee Settlement Agreement and $188 million in Customer Refunds recognized as a regulatory liability in 2017.

Georgia Power estimates that its financing costs for construction of Plant Vogtle Units 3 and 4 will total approximately $3.2 billion, of which $1.7 billion had been incurred through June 30, 2018.

The $0.7 billion increase to the base capital cost forecast reflected in the table above primarily results from changed assumptions related to the finalization of contract scopes and management responsibilities for Bechtel and over 60 subcontractors, labor productivity rates, and craft labor incentives, as well as the related levels of project management, oversight, and support, including field supervision and engineering support.

Although Georgia Power believes these incremental costs are reasonable and necessary to complete the project and the Georgia PSC's order in the seventeenth VCM proceeding specifically states that the construction of Plant Vogtle Units 3 and 4 is not subject to a cost cap, Georgia Power does not intend to seek rate recovery for these cost increases included in the current base capital cost forecast (or any related financing costs), which will be filed with the Georgia PSC in the nineteenth VCM report at the end of August 2018. In connection with future VCM filings, Georgia Power may request the Georgia PSC to evaluate costs currently included in the construction contingency estimate for rate recovery as and when they are appropriately included in the base capital cost forecast. After considering the significant level of uncertainty that exists regarding the future recoverability of costs included in the construction contingency estimate since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in these future regulatory proceedings, Georgia Power has recorded a total pre-tax charge to income of $1.1 billion ($0.8 billion after tax), which includes the total increase in the capital cost forecast and construction contingency estimate as of June 30, 2018.

As construction continues, challenges with management of contractors, subcontractors, and vendors; labor productivity, availability, and/or cost escalation; procurement, fabrication, delivery, assembly, and/or installation, including any required engineering changes, of plant systems, structures, and components (some of which are based on new technology that is just beginning initial operation in the global nuclear industry at this scale); or other issues could arise and change the projected schedule and estimated cost.

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. 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, which may result in additional license amendments or require other resolution. If any license amendment

263

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.

The ultimate outcome of these matters cannot be determined at this time. However, any extension of the project schedule is currently estimated to result in additional base capital costs of approximately $50 million per month, based on Georgia Power's ownership interests, and AFUDC of approximately $12 million per month. While Georgia Power is not precluded from seeking recovery of any future capital cost forecast increase, management will ultimately determine whether or not to seek recovery. Any further changes to the capital cost forecast that are not expected to be recoverable through regulated rates will be required to be charged to income and such charges could be material.

Joint Owner Contracts

In November 2017, the Vogtle Owners entered into an amendment to their joint ownership agreements for Plant Vogtle Units 3 and 4 (as amended, Vogtle Joint Ownership Agreements) to provide for, among other conditions, additional Vogtle Owner approval requirements. Pursuant to the Vogtle Joint Ownership Agreements, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction if certain adverse events occur, including: (i) the bankruptcy of Toshiba; (ii) termination or rejection in bankruptcy of certain agreements, including the Vogtle Services Agreement or the Bechtel Agreement; (iii) the Georgia PSC or Georgia Power determines that any of Georgia Power's costs relating to the construction of Plant Vogtle Units 3 and 4 will not be recovered in retail rates because such costs are deemed unreasonable or imprudent; or (iv) an increase in the construction budget contained in the seventeenth VCM report of more than $1 billion or extension of the project schedule contained in the seventeenth VCM report of more than one year. In addition, pursuant to the Vogtle Joint Ownership Agreements, the required approval of holders of ownership interests in Plant Vogtle Units 3 and 4 is at least (i) 90% for a change of the primary construction contractor and (ii) 67% for material amendments to the Vogtle Services Agreement or agreements with Southern Nuclear or the primary construction contractor, including the Bechtel Agreement.

As a result of the increase in the total project capital cost forecast and Georgia Power's decision not to seek rate recovery of the increase in the base capital costs as described in "Cost and Schedule" herein, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction. The Vogtle Owners are expected to conduct these votes in the third quarter 2018.

If the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 do not vote to continue construction, the Vogtle Joint Ownership Agreements provide that the project will be cancelled, and construction will cease. In the event that fewer than 90% of the Vogtle Owners vote to continue construction, Georgia Power and the other Vogtle Owners will assess options for Plant Vogtle Units 3 and 4. If Plant Vogtle Units 3 and 4 were cancelled and Georgia Power was unable to recover costs it has incurred in connection with the project, Southern Company's and Georgia Power's results of operations, cash flow, and financial condition would be materially impacted. The ultimate outcome of this matter cannot be determined at this time.

Regulatory Matters

In December 2017, the Georgia PSC voted to approve (and issued its related order on January 11, 2018) Georgia Power's recommendation to continue construction and resolved the following regulatory matters related to Plant Vogtle Units 3 and 4: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report should be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement was reasonable and prudent and none of the amounts paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) (a) capital costs incurred up to $5.68 billion would be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, (b) Georgia Power would have the burden to show that any capital costs above $5.68 billion were prudent, and (c) a revised capital cost forecast of $7.3 billion (after reflecting the impact of payments received under the Guarantee Settlement Agreement and Customer Refunds) was found reasonable; (iv) construction of Plant Vogtle Units 3 and 4 should be completed, with Southern Nuclear serving as project manager and Bechtel as

264

primary contractor; (v) approved and deemed reasonable Georgia Power's revised schedule placing Plant Vogtle Units 3 and 4 in service in November 2021 and November 2022, respectively; (vi) confirmed that the revised cost forecast does not represent a cost cap and that prudence decisions on cost recovery will be made at a later date, consistent with applicable Georgia law; (vii) reduced the ROE used to calculate the NCCR tariff (a) from 10.95% (the ROE rate setting point authorized by the Georgia PSC in the 2013 ARP) to 10.00% effective January 1, 2016, (b) from 10.00% to 8.30%, effective January 1, 2020, and (c) from 8.30% to 5.30%, effective January 1, 2021 (provided that the ROE in no case will be less than Georgia Power's average cost of long-term debt); (viii) reduced the ROE used for AFUDC equity for Plant Vogtle Units 3 and 4 from 10.00% to Georgia Power's average cost of long-term debt, effective January 1, 2018; and (ix) agreed that upon Unit 3 reaching commercial operation, retail base rates would be adjusted to include carrying costs on those capital costs deemed prudent in the Vogtle Cost Settlement Agreement. The January 11, 2018 order also stated that if Plant Vogtle Units 3 and 4 are not commercially operational by June 1, 2021 and June 1, 2022, respectively, the ROE used to calculate the NCCR tariff will be further reduced by 10 basis points each month (but not lower than Georgia Power's average cost of long-term debt) until the respective unit is commercially operational. The ROE reductions negatively impacted earnings by approximately $25 million in 2017 and are estimated to have negative earnings impacts of approximately $100 million in 2018 and an aggregate of $585 million from 2019 to 2022.

In its January 11, 2018 order, the Georgia PSC also stated if other conditions change and assumptions upon which Georgia Power's seventeenth VCM report are based do not materialize, the Georgia PSC reserved the right to reconsider the decision to continue construction.

On February 12, 2018, Georgia Interfaith Power & Light, Inc. and Partnership for Southern Equity, Inc. filed a petition appealing the Georgia PSC's January 11, 2018 order with the Fulton County Superior Court. On March 8, 2018, Georgia Watch filed a similar appeal to the Fulton County Superior Court for judicial review of the Georgia PSC's final decision and denial of Georgia Watch's motion for reconsideration. Georgia Power believes the two appeals have no merit; however, an adverse outcome in either appeal could have a material impact on Southern Company's and Georgia Power's results of operations, financial condition, and liquidity.

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

See Note (B) to the Condensed Financial Statements under "Nuclear Construction" herein for additional information regarding Plant Vogtle Units 3 and 4.

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.

(2) Plan of acquisition, reorganization, arrangement, liquidation or succession
Southern Company
(a)1	-	Stock Purchase Agreement, dated as of May 20, 2018, by and among Southern Company, 700 Universe, LLC, and NextEra Energy. (Designated in Form 8-K dated May 23, 2018, File No. 1-3526, as Exhibit 2(a)1.)**
(a)2	-	Stock Purchase Agreement, dated as of May 20, 2018, by and among Southern Company Gas, NUI Corporation, 700 Universe, LLC, and NextEra Energy. (Designated in Form 8-K dated May 23, 2018, File No. 1-3526, as Exhibit 2(a)2.)**
(a)3	-	Equity Interest Purchase Agreement, dated as of May 20, 2018, by and among Southern Power Company, 700 Universe, LLC, and NextEra Energy. (Designated in Form 8-K dated May 23, 2018, File No. 1-3526, as Exhibit 2(a)3.)**

265

		Gulf Power
		(d)1	-	Stock Purchase Agreement, dated as of May 20, 2018, by and among Southern Company, 700 Universe, LLC, and NextEra Energy. See Exhibit 2(a)1 herein.**
		Southern Power
		(f)1	-	Equity Interest Purchase Agreement, dated as of May 20, 2018, by and among Southern Power Company, 700 Universe, LLC, and NextEra Energy. See Exhibit 2(a)3 herein.**
		(4) Instruments Describing Rights of Security Holders, Including Indentures
		Alabama Power
		(b)1	-	Fifty-Eighth Supplemental Indenture to Senior Note Indenture, dated as of June 28, 2018, providing for the issuance of the Series 2018A 4.18% Senior Notes due July 15, 2048. (Designated in Form 8-K dated June 21, 2018, File No. 1-3164, as Exhibit 4.6.)
		(10) Material Contracts
		Southern Company
#	*	(a)1	-	Consulting Agreement between SCS and Arthur P. Beattie effective August 1, 2018.
		(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, 2017, File No. 1-3526 as Exhibit 24(a).)
	*	(a)2	-	Power of Attorney for Andrew W. Evans.
		Alabama Power
		(b)	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2017, 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, 2017, 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, 2017, File No. 001-31737 as Exhibit 24(d).)
		Mississippi Power
		(e)	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2017, File No. 001-11229 as Exhibit 24(e).)
		Southern Power
		(f)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2017, File No. 001-37803 as Exhibit 24(f).)
		(f)2	-	Power of Attorney for Mark S. Lantrip. (Designated in Form 10-Q for the quarter ended March 31, 2018, File No. 001-37803, as Exhibit 24(f)2.)
		Southern Company Gas
		(g)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2017, File No. 1-14174 as Exhibit 24(g).)

266

*	(g)2	-	Power of Attorney for Kimberly S. Greene.
	(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.
	Southern Company Gas
*	(g)1	-	Certificate of Southern Company Gas' Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
*	(g)2	-	Certificate of Southern Company Gas' Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

267

	(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.
	Southern Company Gas
*	(g)	-	Certificate of Southern Company Gas' 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
**	Schedules and exhibits have been omitted pursuant to Item 601(b)(2) of Regulation S-K. A copy of any omitted schedule or exhibit will be furnished supplementally to the Securities and Exchange Commission upon request; provided, however, that each registrant may request confidential treatment pursuant to Rule 24b-2 of the Securities Exchange Act of 1934, as amended, for any schedules or exhibits so furnished.

268

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	Andrew W. Evans
	Executive Vice President and Chief Financial Officer
	(Principal Financial Officer)
By	/s/ Melissa K. Caen
	(Melissa K. Caen, Attorney-in-fact)

Date: August 7, 2018

269

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 7, 2018

270

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	Xia Liu
	Executive Vice President, Chief Financial Officer, and Treasurer
	(Principal Financial Officer)
By	/s/ Melissa K. Caen
	(Melissa K. Caen, Attorney-in-fact)

Date: August 7, 2018

271

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	Robin B. Boren
	Vice President, Chief Financial Officer, and Treasurer
	(Principal Financial Officer)
By	/s/ Melissa K. Caen
	(Melissa K. Caen, Attorney-in-fact)

Date: August 7, 2018

272

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
	Chairman, 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 7, 2018

273

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	Mark S. Lantrip
	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 7, 2018

274

SOUTHERN COMPANY GAS

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 COMPANY GAS
By	Kimberly S. Greene
	Chairman, President, and Chief Executive Officer
	(Principal Executive Officer)
By	Elizabeth W. Reese
	Executive Vice President, Chief Financial Officer, and Treasurer
	(Principal Financial Officer)
By	/s/ Melissa K. Caen
	(Melissa K. Caen, Attorney-in-fact)

Date: August 7, 2018

275

EX-10.A1

Exhibit 10(a)1

CONSULTING AGREEMENT

This CONSULTING AGREEMENT (“Agreement”) is entered into by and between Southern Company Services, Inc. (the “Company”) and Arthur P. Beattie (“Consultant”).

WITNESSETH:

WHEREAS, the Company desires to retain Consultant to provide certain services to the Company, and Consultant desires to provide such services to the Company, all subject to the terms and conditions set forth herein.

NOW THEREFORE, for and in consideration of the premises, the mutual covenants and agreements contained herein, and for other good and valuable consideration, the receipt, sufficiency and adequacy of which are hereby acknowledged, the parties hereby agree as follows:

1. Engagement as an Independent Consultant.

The Company hereby agrees to engage Consultant as an independent contractor, and Consultant hereby accepts such engagement as an independent contractor, upon the terms and conditions set forth in this Agreement.

2. Term.

The term of this Agreement shall commence on August 1, 2018 and shall expire on December 31, 2018 (“Term”).

3. Duties.

Unless otherwise detailed in a specific letter or memorandum, Consultant shall manage, perform and provide professional consulting services and advice (“Consulting Services”) as the Company may request from time to time. Consultant shall be available to provide Consulting Services for the Company during the Term of this Agreement. The parties expect that Consultant’s work, on average, will not exceed 40 hours per month during the Term of this Agreement. Consultant must obtain prior written approval from an authorized officer of the Company before Consultant contracts with or in any other way employs any agents or subcontractors to perform work in any way related to this Agreement. Consultant shall cause its agents, employees and subcontractors to perform such duties in a professional and competent manner which shall be consistent with the Southern Company Code of Ethics. Additionally, during the Term of this Agreement, Consultant agrees to promote the best interests of the Company and to take no actions that in any way damage the public image or reputation of the Company or its affiliates or to knowingly assist, in any way, a competitor of the Company.

4. Consultant as an Independent Contractor.

In the performance of this Agreement, both Consultant and the Company will be acting in their own separate capacities and not as agents, employees, partners, joint venturers or associates

of one another. It is expressly understood and agreed that Consultant is an independent contractor of the Company in all manners and respects. The parties further agree that:

(a) Consultant is not authorized to bind the Company to any liability or obligation or to represent that Consultant has any such authority.

(b) Consultant shall obtain and maintain (at Consultant’s own cost) any required insurance or other protection required for the performance of the services under this Agreement.

(c) Consultant shall be solely and exclusively responsible and liable for all other expenses, costs, liabilities, assessments, taxes, maintenance, insurance, undertakings and other obligations incurred by Consultant at any time and for any reason as a result of this Agreement or the performance of services by Consultant. However, Consultant may be reimbursed for reasonable out-of-pocket expenses in accordance with the Company’s policies where prior approval has been received from a Company Officer.

(d) Consultant shall be solely and exclusively responsible for obtaining and providing (at Consultant’s own cost) whatever computer, training, software or other equipment Consultant believes is necessary to complete the services required under this Agreement. Company shall make available to Consultant any Company information or other material determined in the Company’s sole discretion to be necessary for Consultant to provide any requested Consulting Services.

(e) Consultant shall complete the services required under this Agreement according to Consultant’s own means and methods of work which shall be in the exclusive charge and control of Consultant and which shall not be subject to the control or supervision of Company, except as to the results of the work.

(f) Consultant shall not be subject to the Company’s employee personnel policies and procedures. Other than as a retired employee of the Company, Consultant also shall not be eligible to receive any employee benefits or participate in any employee benefit plan sponsored by the Company, including, but not limited to, any retirement plan, insurance program, disability plan, medical benefits plan or any other fringe benefit program sponsored and maintained by the Company for its employees.

(g) The Company and Consultant acknowledge and agree that Consultant shall not provide the services to Company on a full-time basis. Except to the extent restricted under this Agreement, the Consultant may engage in other activities for and on behalf of other clients during the Term of this Agreement.

5. Retainer Fee.

As payment for the Consulting Services rendered pursuant to this Agreement, the Company shall pay, and Consultant shall accept, a retainer fee in the amount of $400,000.00. The payment of the retainer fee shall be made in five equal installments of $80,000.00. Each installment will be payable on the first day of each month of the Term of the Agreement, or as soon as practicable after such date.

6. Termination.

The parties to the Agreement may mutually agree in writing to terminate the Agreement prior to the expiration of the Term. The Company may terminate the Agreement for cause if Consultant does not perform Consulting Services under this Agreement in a satisfactory manner that protects the business interests of the Company. This Agreement will terminate automatically on the death of Consultant. Any remaining unpaid retainer fee installments shall be forfeited by Consultant if the Agreement is terminated prior to the expiration of the Term.

7. Confidential Information; Trade Secrets; Ownership of Work Product.

(a) For purposes of this Agreement, the following terms shall have the following respective meanings:

(1) “Confidential Information” shall mean the proprietary or confidential data, information, documents, or materials (whether oral, written, electronic, or otherwise) belonging to or pertaining to the Company or any current or former subsidiaries or affiliates of The Southern Company (collectively, “Southern Entities”), other than Trade Secrets (as defined below), which is of tangible or intangible value to any of the Southern Entities and the details of which are not generally known to the competitors of the Southern Entities. Confidential Information shall also include: (A) any items that any of the Southern Entities have marked CONFIDENTIAL or some similar designation or are otherwise identified as being confidential; and (B) all non-public information known by or in the possession of Consultant related to or regarding any proceedings involving or related to the Southern Entities before any federal or state regulatory agencies.

(2) “Entity or Entities” shall mean any person, business, individual, partnership, joint venture, agency, governmental agency, body or subdivision, association, firm, corporation, limited liability company, or other entity of any kind.

(3) “Trade Secrets” shall mean information or data of or about any of the Southern Entities, including, but not limited to, technical or non-technical data, formulas, patterns, compilations, programs, devices, methods, techniques, drawings, processes, financial data, financial plans, product plans, or lists of actual or potential customers or suppliers that: (A) derives economic value, actual or potential, from not being generally known to, and not being readily ascertainable by proper means by, other persons who can obtain economic value from its disclosure or use and (B) is the subject of efforts that are reasonable under the circumstances to maintain its secrecy. Consultant agrees that Trade Secrets include non-public information related to the rate-making process of the Southern Entities and any other information which is defined as a trade secret under applicable law.

(4) “Work Product” shall mean all tangible work product, property, data, documentation, concepts or plans, inventions, improvements, techniques, and

processes relating to the Southern Entities that were conceived, discovered, created, written, revised, or developed by Consultant conceived, discovered, developed or created by Consultant in performing the Consulting Services pursuant to this Agreement.

(b) In recognition of the need of the Company to protect its legitimate business interests, Confidential Information, and Trade Secrets, Consultant hereby covenants and agrees that Consultant shall regard and treat Trade Secrets and all Confidential Information as strictly confidential and wholly-owned by the Southern Entities and shall not, for any reason, in any fashion, either directly or indirectly, use, sell, lend, lease, distribute, license, give, transfer, assign, show, disclose, disseminate, reproduce, copy, misappropriate, or otherwise communicate any such item or information to any third party Entity for any purpose other than in accordance with the Agreement or as required by applicable law: (A) with regard to each item constituting a Trade Secret, at all times such information remains a trade secret under applicable law and (B) with regard to any Confidential Information, for a period of three years following the end of the Term of the Agreement.

(c) Consultant shall exercise best efforts to ensure the continued confidentiality of all Trade Secrets and Confidential Information and shall immediately notify the Company of any unauthorized disclosure or use of any Trade Secrets or Confidential Information of which Consultant becomes aware. Consultant shall assist the Southern Entities, to the extent necessary, in the protection of or procurement of any intellectual property protection or other rights in any of the Trade Secrets or Confidential Information.

(d) All Work Product shall be owned exclusively by the Company. To the greatest extent possible, any Work Product shall be deemed to be work made for hire (as defined in the Copyright Act, 17 U.S.C.A. § 101 et seq., as amended), and Consultant hereby unconditionally and irrevocably transfers and assigns to the Company all right, title, and interest Consultant currently has or may have by operation of law or otherwise in or to any Work Product, including, without limitation, all patents, copyrights, trademarks (and the goodwill associated therewith), trade secrets, service marks (and the goodwill associated therewith), and other intellectual property rights. Consultant agrees to execute and deliver to the Company any transfers, assignments, documents or other instruments which the Company may deem necessary or appropriate, from time to time, to protect the rights granted herein or to vest complete title and ownership of any and all Work Product, and all associated intellectual property and other rights therein, exclusively in the Company.

(e) Notwithstanding anything herein to the contrary, nothing in this Agreement will prevent Consultant from providing truthful testimony under oath in a judicial or administrative proceeding or prevent Consultant from providing information to a federal, state, or local agency in connection with the lawful exercise of such agency’s functions. Moreover, nothing in this Agreement is intended to prohibit Consultant from engaging in protected activities under applicable law (including protected activities described in Section 211 of

the Energy Reorganization Act). Consultant further understands nothing in this Agreement limits Consultant’s ability to file a charge or complaint with the Securities and Exchange Commission or any other federal, state or local government agency or commission (‘Government Agencies”). Nothing in this Agreement limits Consultant’s ability to communicate with any Government Agencies or otherwise participate in any investigation or proceeding that may be conducted by the Government Agency, including providing documents or information without notice to the Company. This Agreement does not limit Consultant’s right to receive an award for information provided to any Government Agency.

8. Remedies.

The parties represent and agree that any disclosure or use of any Trade Secrets or Confidential Information by Consultant except as otherwise permitted under this Agreement or authorized by the Company in writing, or any other violation of Section 7, would be wrongful and cause immediate, significant, continuing and irreparable injury and damage to Company that is not fully compensable by monetary damages. Should Consultant breach or threaten to breach any provisions of Section 7, the Company shall be entitled to obtain immediate relief and remedies in a court of competent jurisdiction (including but not limited to damages, preliminary or permanent injunctive relief and an accounting for all profits and benefits arising out of Consultant’s breach), cumulative of and in addition to any other rights or remedies to which Company may be entitled by this Agreement, at law or in equity.

9. Return of Materials.

By no later than the end of the Term, Consultant agrees to return to the Company all property of the Southern Entities, including but not limited to data, lists, information, memoranda, documents, identification cards, parking cards, keys, computers, fax machines, pagers, phones, files, and any and all written or descriptive materials of any kind belonging or relating to the Company or any other Southern Entity, including, without limitation, any originals, copies, and abstracts containing any Work Product, intellectual property, Confidential Information, and Trade Secrets in Consultant’s possession or control.

10. Laws, Regulations and Public Ordinances.

Consultant shall comply with all federal, state, and local statutes, regulations, and public ordinances governing Consultant’s work hereunder and shall indemnify, defend and hold the Company harmless from any and all liability, damage, cost, fine, penalty, fee, and expense arising from Consultant’s failure to do so.

11. Notices.

All notices required, necessary or desired to be given pursuant to this Agreement shall be in writing and shall be effective when delivered or on the third day following the date upon which such notice is deposited, postage prepaid, in the United States mail, certified return receipt requested, and addressed to the party at the address set forth below:

If to Consultant: Arthur P. Beattie [Home address on file] If to the Company: Southern Company Services, Inc. 30 Ivan Allen Jr. Blvd., NW Atlanta, GA 30308 Attention: Nancy Sykes

12. Indemnification.

Consultant shall and does hereby expressly agree to indemnify and hold harmless the Company, its officers, directors, shareholders, employees, parent, and affiliates against any and all suits, actions, judgments, costs (including, without limitation, all court costs and attorneys’ fees), losses, damages, or claims of whatever nature arising out of or related to any acts or omissions of Consultant, Consultant’s agents, employees, or subcontractors, including, but not limited to, any injuries to or deaths of persons or any damage to property or equipment. Consultant further agrees to defend any and all such actions in any court or in arbitration.

13. Waiver of Breach.

The waiver of a breach of any provision of the Agreement shall not operate or be construed as a waiver of any other breach. Each of the parties to the Agreement will be entitled to enforce its or his/her rights under the Agreement, specifically, to recover damages by reason of any breach of any provision of the Agreement and to exercise all other rights existing in its or his/her favor.

14. Assignment by Consultant.

Consultant may not assign, transfer or subcontract any of Consultant’s rights or obligations under this Agreement to any party without the prior written consent of the Company. Consultant’s obligations under this Agreement shall be binding on Consultant’s successors and permitted assigns. Any assignment, transfer or subcontracting in violation of this provision shall be null and void.

15. Governing Law.

This Agreement shall be construed and enforced in accordance with the laws of the State of Georgia.

16. Severability.

The unenforceability or invalidity of any particular provision of the Agreement shall not affect its other provisions, and to the extent necessary to give such other provisions effect, they shall be deemed severable. If any of the provisions of the Agreement are determined by any court of law or equity with jurisdiction over this matter to be unreasonable or unenforceable, in whole or in part, as written, the parties hereby consent to and affirmatively request that said court reform the provision so as to be reasonable and enforceable and that said court enforce the provision as reformed. Consultant acknowledges and agrees that the covenants and agreements contained in the Agreement shall be construed as covenants and agreements independent of each

other or any other contract between the parties hereto and that the existence of any claim or cause of action by Consultant against the Company or any Southern Entity, whether predicated upon the Agreement or any other contract, shall not constitute a defense to the enforcement by the Company or any Southern Entity of the covenants and agreements.

17. Interpretation.

The judicial body interpreting the Agreement shall not construe the terms of the Agreement more strictly against one party, it being agreed that both parties and/or their attorneys or agents have negotiated and participated in the preparation hereof.

18. Survival.

Notwithstanding any expiration or termination of this Agreement, the provisions of Sections 8, 10, and 12 through 19 hereof shall survive and remain in full force and effect, as shall any other provision hereof that, by its terms or reasonable interpretation thereof, sets forth obligations that extend beyond the termination of this Agreement.

19. Entire Agreement.

This Agreement embodies the entire agreement of the parties and supersedes all prior agreements between the parties hereto relating to the subject matter hereof. This Agreement may not be modified or amended except by a written instrument signed by both Consultant and an authorized representative of the Company.

[Signatures are on following page.]

IN WITNESS WHEREOF, the undersigned have executed the Agreement on the dates set forth below.

COMPANY
Signature:		/s/Thomas A Fanning
Printed Name:			Thomas A. Fanning
Title:	President, Chairman, and Chief Executive Officer of
	The Southern Company
Date:	May 23, 2018

CONSULTANT
Signature:		/s/Art P. Beattie
Date:	May 23, 2018

EX-24.A2

Exhibit 24(a)2

Andrew W. Evans Chief Financial Officer 30 Ivan Allen Jr. Boulevard NW Atlanta, GA 30308 404 506 5000 tel southerncompany.com

July 23, 2018

Myra C. Bierria and Melissa K. Caen

Ms. Bierria and Ms. Caen:

As an officer of The Southern Company, I hereby make, constitute, and appoint you my true and lawful Attorney in my name, place, and stead, to sign and cause to be filed with the Securities and Exchange Commission (1) the Company's Quarterly Reports on Form 10-Q during 2018 and (2) any necessary or appropriate amendment or amendments to any such reports or to the Company’s Annual Report on Form 10-K for the year ended December 31, 2017, each such report or amendments to such reports to be accompanied in each case by any necessary or appropriate exhibits or schedules thereto.

Yours very truly,

/s/Andrew W. Evans

Andrew W. Evans

Executive Vice President and

Chief Financial Officer

EX-24.G2

Exhibit 24(g)2

10 Peachtree Place NE Atlanta, GA 30309

July 31, 2018

Myra C. Bierria, Melissa K. Caen and Barbara P. Christopher

Ms. Bierria, Ms. Caen and Ms. Christopher:

As a director and an officer of Southern Company Gas, I hereby make, constitute, and appoint you my true and lawful Attorney in my name, place, and stead, to sign and cause to be filed with the Securities and Exchange Commission (1) the Company's Quarterly Reports on Form 10-Q during 2018 and (2) any necessary or appropriate amendment or amendments to any such reports or to the Company’s Annual Report on Form 10-K for the year ended December 31, 2017, each such report or amendments to such reports to be accompanied in each case by any necessary or appropriate exhibits or schedules thereto.

Yours very truly,

/s/Kimberly S. Greene

Kimberly S. Greene

EX-31.A1

Exhibit 31(a)1

THE SOUTHERN COMPANY

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, Thomas A. Fanning, certify that:

1. I have reviewed this quarterly report on Form 10-Q of The Southern Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  August 7, 2018

/s/Thomas A. Fanning

Thomas A. Fanning

Chairman, President and

Chief Executive Officer

EX-31.A2

Exhibit 31(a)2

THE SOUTHERN COMPANY

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, Andrew W. Evans, certify that:

1. I have reviewed this quarterly report on Form 10-Q of The Southern Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  August 7, 2018

/s/Andrew W. Evans

Andrew W. Evans

Executive Vice President and Chief Financial Officer

EX-31.B1

Exhibit 31(b)1

ALABAMA POWER COMPANY

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, Mark A. Crosswhite, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Alabama Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  August 7, 2018

/s/Mark A. Crosswhite

Mark A. Crosswhite

Chairman, President and Chief Executive Officer

EX-31.B2

Exhibit 31(b)2

ALABAMA POWER COMPANY

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, Philip C. Raymond, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Alabama Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  August 7, 2018

/s/Philip C. Raymond

Philip C. Raymond

Executive Vice President, Chief Financial Officer

and Treasurer

EX-31.C1

Exhibit 31(c)1

GEORGIA POWER COMPANY

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, W. Paul Bowers, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Georgia Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  August 7, 2018

/s/W. Paul Bowers

W. Paul Bowers

Chairman, President and Chief Executive Officer

EX-31.C2

Exhibit 31(c)2

GEORGIA POWER COMPANY

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, Xia Liu, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Georgia Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  August 7, 2018

/s/Xia Liu

Xia Liu

Executive Vice President, Chief Financial Officer and Treasurer

EX-31.D1

Exhibit 31(d)1

GULF POWER COMPANY

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, S. W. Connally, Jr., certify that:

1. I have reviewed this quarterly report on Form 10-Q of Gulf Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  August 7, 2018

/s/S. W. Connally, Jr.

S. W. Connally, Jr.

Chairman, President and Chief Executive Officer

EX-31.D2

Exhibit 31(d)2

GULF POWER COMPANY

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, Robin B. Boren, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Gulf Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  August 7, 2018

/s/Robin B. Boren

Robin B. Boren

Vice President, Chief Financial Officer and Treasurer

EX-31.E1

Exhibit 31(e)1

MISSISSIPPI POWER COMPANY

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, Anthony L. Wilson, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Mississippi Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  August 7, 2018

/s/Anthony L. Wilson

Anthony L. Wilson

Chairman, President and

 Chief Executive Officer

EX-31.E2

Exhibit 31(e)2

MISSISSIPPI POWER COMPANY

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, Moses H. Feagin, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Mississippi Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  August 7, 2018

/s/Moses H. Feagin

Moses H. Feagin

Vice President, Treasurer and

Chief Financial Officer

EX-31.F1

Exhibit 31(f)1

SOUTHERN POWER COMPANY

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, Mark S. Lantrip, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Southern Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:   August 7, 2018

/s/Mark S. Lantrip

Mark S. Lantrip

Chairman, President and Chief Executive Officer

EX-31.F2

Exhibit 31(f)2

SOUTHERN POWER COMPANY

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, William C. Grantham, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Southern Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  August 7, 2018

/s/William C. Grantham

William C. Grantham

Senior Vice President, Treasurer and Chief

Financial Officer

EX-31.G1

Exhibit 31(g)1

SOUTHERN COMPANY GAS

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, Kimberly S. Greene, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Southern Company Gas;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  August 7, 2018

/s/Kimberly S. Greene

Kimberly S. Greene

Chairman, President, and Chief Executive Officer

EX-31.G2

Exhibit 31(g)2

SOUTHERN COMPANY GAS

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, Elizabeth W. Reese, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Southern Company Gas;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  August 7, 2018

/s/Elizabeth W. Reese

Elizabeth W. Reese

Executive Vice President, Chief Financial

Officer, and Treasurer

EX-32.A

Exhibit 32(a)

CERTIFICATION

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the accompanying Quarterly Report on Form 10-Q of The Southern Company for the quarter ended June 30, 2018, we, the undersigned, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of our individual knowledge and belief, that:

(1) such Quarterly Report on Form 10-Q of The Southern Company for the quarter ended June 30, 2018, which this statement accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in such Quarterly Report on Form 10-Q of The Southern Company for the quarter ended June 30, 2018, fairly presents, in all material respects, the financial condition and results of operations of The Southern Company.

/s/Thomas A. Fanning

Thomas A. Fanning

Chairman, President and

Chief Executive Officer

/s/Andrew W. Evans

Andrew W. Evans

Executive Vice President and

Chief Financial Officer

August 7, 2018

EX-32.B

Exhibit 32(b)

CERTIFICATION

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the accompanying Quarterly Report on Form 10-Q of Alabama Power Company for the quarter ended June 30, 2018, we, the undersigned, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of our individual knowledge and belief, that:

(1) such Quarterly Report on Form 10-Q of Alabama Power Company for the quarter ended June 30, 2018, which this statement accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in such Quarterly Report on Form 10-Q of Alabama Power Company for the quarter ended June 30, 2018, fairly presents, in all material respects, the financial condition and results of operations of Alabama Power Company.

/s/Mark A. Crosswhite

Mark A. Crosswhite

Chairman, President and Chief Executive Officer

/s/Philip C. Raymond

Philip C. Raymond

Executive Vice President,

Chief Financial Officer and Treasurer

August 7, 2018

EX-32.C

Exhibit 32(c)

CERTIFICATION

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the accompanying Quarterly Report on Form 10-Q of Georgia Power Company for the quarter ended June 30, 2018, we, the undersigned, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of our individual knowledge and belief, that:

(1) such Quarterly Report on Form 10-Q of Georgia Power Company for the quarter ended June 30, 2018, which this statement accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in such Quarterly Report on Form 10-Q of Georgia Power Company for the quarter ended June 30, 2018, fairly presents, in all material respects, the financial condition and results of operations of Georgia Power Company.

/s/W. Paul Bowers

W. Paul Bowers

Chairman, President and Chief Executive Officer

/s/Xia Liu

Xia Liu

Executive Vice President, Chief Financial Officer and Treasurer

August 7, 2018

EX-32.D

Exhibit 32(d)

CERTIFICATION

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the accompanying Quarterly Report on Form 10-Q of Gulf Power Company for the quarter ended June 30, 2018, we, the undersigned, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of our individual knowledge and belief, that:

(1) such Quarterly Report on Form 10-Q of Gulf Power Company for the quarter ended June 30, 2018, which this statement accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in such Quarterly Report on Form 10-Q of Gulf Power Company for the quarter ended June 30, 2018, fairly presents, in all material respects, the financial condition and results of operations of Gulf Power Company.

/s/S. W. Connally, Jr.

S. W. Connally, Jr.

Chairman, President and Chief Executive Officer

/s/Robin B. Boren

Robin B. Boren

Vice President, Chief Financial Officer and Treasurer

August 7, 2018

EX-32.E

Exhibit 32(e)

CERTIFICATION

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the accompanying Quarterly Report on Form 10-Q of Mississippi Power Company for the quarter ended June 30, 2018, we, the undersigned, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of our individual knowledge and belief, that:

(1) such Quarterly Report on Form 10-Q of Mississippi Power Company for the quarter ended June 30, 2018, which this statement accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in such Quarterly Report on Form 10-Q of Mississippi Power Company for the quarter ended June 30, 2018, fairly presents, in all material respects, the financial condition and results of operations of Mississippi Power Company.

/s/Anthony L. Wilson

Anthony L. Wilson

Chairman, President and Chief Executive Officer

/s/Moses H. Feagin

Moses H. Feagin

Vice President, Treasurer and

Chief Financial Officer

August 7, 2018

EX-32.F

Exhibit 32(f)

CERTIFICATION

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the accompanying Quarterly Report on Form 10-Q of Southern Power Company for the quarter ended June 30, 2018, we, the undersigned, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of our individual knowledge and belief, that:

(1) such Quarterly Report on Form 10-Q of Southern Power Company for the quarter ended June 30, 2018, which this statement accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in such Quarterly Report on Form 10-Q of Southern Power Company for the quarter ended June 30, 2018, fairly presents, in all material respects, the financial condition and results of operations of Southern Power Company.

/s/Mark S. Lantrip

Mark S. Lantrip

 Chairman, President

and Chief Executive Officer

/s/William C. Grantham

William C. Grantham

Senior Vice President, Treasurer and

Chief Financial Officer

August 7, 2018

EX-32.G

Exhibit 32(g)

CERTIFICATION

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO SECTION 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the accompanying Quarterly Report on Form 10-Q of Southern Company Gas for the quarter ended June 30, 2018, we, the undersigned, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of our individual knowledge and belief, that:

(1) such Quarterly Report on Form 10-Q of Southern Company Gas for the quarter ended June 30, 2018, which this statement accompanies, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in such Quarterly Report on Form 10-Q of Southern Company Gas for the quarter ended June 30, 2018, fairly presents, in all material respects, the financial condition and results of operations of Southern Company Gas.

/s/Kimberly S. Greene

Kimberly S. Greene

Chairman, President, and Chief Executive Officer

/s/Elizabeth W. Reese

Elizabeth W. Reese

Executive Vice President, Chief Financial

Officer, and Treasurer

August 7, 2018

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Document and Entity Information	6 Months Ended
	Jun. 30, 2018 shares
Document Information [Line Items]
Entity Registrant Name	SOUTHERN CO
Entity Central Index Key	0000092122
Document Type	10-Q
Document Period End Date	Jun. 30, 2018
Amendment Flag	false
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	Q2
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding (in shares)	1,014,136,083
ALABAMA POWER CO
Document Information [Line Items]
Entity Registrant Name	ALABAMA POWER CO
Entity Central Index Key	0000003153
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding (in shares)	30,537,500
GEORGIA POWER CO
Document Information [Line Items]
Entity Registrant Name	GEORGIA POWER CO
Entity Central Index Key	0000041091
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding (in shares)	9,261,500
GULF POWER CO
Document Information [Line Items]
Entity Registrant Name	GULF POWER CO
Entity Central Index Key	0000044545
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding (in shares)	7,392,717
MISSISSIPPI POWER CO
Document Information [Line Items]
Entity Registrant Name	MISSISSIPPI POWER CO
Entity Central Index Key	0000066904
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding (in shares)	1,121,000
SOUTHERN POWER CO
Document Information [Line Items]
Entity Registrant Name	SOUTHERN POWER CO
Entity Central Index Key	0001160661
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding (in shares)	1,000
SOUTHERN Co GAS
Document Information [Line Items]
Entity Registrant Name	SOUTHERN Co GAS
Entity Central Index Key	0001004155
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding (in shares)	100

XML

Condensed Consolidated Statements of Income (Unaudited) - USD ($) shares in Millions, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Operating Revenues:
Retail electric revenues	$ 3,740	$ 3,777	$ 7,308	$ 7,171
Wholesale electric revenues	611	618	1,230	1,149
Other electric revenues	175	167	339	342
Natural gas revenues (includes alternative revenue programs of $(4), $-, $(27), and $9, respectively)	706	684	2,314	2,214
Alternative revenue programs	(4)	0	(27)	9
Other revenues	395	184	808	326
Total operating revenues	5,627	5,430	11,999	11,202
Operating Expenses:
Fuel	1,103	1,092	2,204	2,088
Purchased power	236	211	503	390
Cost of natural gas	228	232	949	951
Cost of other sales	279	114	568	203
Other operations and maintenance	1,559	1,356	3,008	2,740
Depreciation and amortization	783	754	1,552	1,469
Taxes other than income taxes	316	308	671	638
Estimated loss on plants under construction	1,060	3,012	1,105	3,120
Asset impairment			161	0
Goodwill impairment			42
Total operating expenses	5,564	7,079	10,560	11,599
Operating Income (Loss)	63	(1,649)	1,439	(397)
Other Income and (Expense):
Allowance for equity funds used during construction	32	58	63	115
Earnings from equity method investments	31	28	72	67
Interest expense, net of amounts capitalized	(470)	(424)	(928)	(840)
Other income (expense), net	78	52	138	98
Total other income and (expense)	(329)	(286)	(655)	(560)
Earnings (Loss) Before Income Taxes	(266)	(1,935)	784	(957)
Income taxes (benefit)	(139)	(587)	(25)	(273)
Consolidated Net Income (Loss)	(127)	(1,348)	809	(684)
Less:
Dividends on preferred and preference stock of subsidiaries	4	11	8	22
Net income attributable to noncontrolling interests	23	22	17	17
Net Income (Loss)	$ (154)	$ (1,381)	$ 784	$ (723)
Earnings (loss) per share —
Basic (in dollars per share)	$ (0.15)	$ (1.38)	$ 0.77	$ (0.73)
Diluted (in dollars per share)	$ (0.15)	$ (1.37)	$ 0.77	$ (0.72)
Average number of shares of common stock outstanding (in millions)
Basic (in shares)	1,014	998	1,012	996
Diluted (in shares)	1,014	1,005	1,017	1,003
Cash dividends paid per share of common stock (in dollars per share)	$ 0.60	$ 0.58	$ 1.18	$ 1.14
ALABAMA POWER CO
Operating Revenues:
Retail electric revenues	$ 1,338	$ 1,333	$ 2,624	$ 2,560
Wholesale revenues, non-affiliates	65	68	139	133
Wholesale revenues, affiliates	31	32	82	65
Other revenues	69	51	131	108
Total operating revenues	1,503	1,484	2,976	2,866
Operating Expenses:
Fuel	347	303	672	601
Purchased power, non-affiliates	48	40	113	75
Purchased power, affiliates	43	34	80	62
Other operations and maintenance	402	389	788	772
Depreciation and amortization	189	183	379	364
Taxes other than income taxes	94	95	192	191
Total operating expenses	1,123	1,044	2,224	2,065
Operating Income (Loss)	380	440	752	801
Other Income and (Expense):
Allowance for equity funds used during construction	14	8	27	16
Interest expense, net of amounts capitalized	(80)	(77)	(158)	(153)
Other income (expense), net	12	15	15	25
Total other income and (expense)	(54)	(54)	(116)	(112)
Earnings (Loss) Before Income Taxes	326	386	636	689
Income taxes (benefit)	64	151	145	277
Consolidated Net Income (Loss)	262	235	491	412
Less:
Dividends on preferred and preference stock of subsidiaries	3	5	7	9
Net Income (Loss)	259	230	484	403
GEORGIA POWER CO
Operating Revenues:
Retail electric revenues	1,889	1,904	3,688	3,593
Wholesale revenues, non-affiliates	36	40	80	79
Wholesale revenues, affiliates	3	9	13	17
Other revenues	120	95	227	191
Total operating revenues	2,048	2,048	4,008	3,880
Operating Expenses:
Fuel	378	445	790	815
Purchased power, non-affiliates	111	103	233	191
Purchased power, affiliates	178	138	349	310
Other operations and maintenance	457	417	863	816
Depreciation and amortization	230	223	458	444
Taxes other than income taxes	106	101	214	199
Estimated loss on plants under construction	1,060	0	1,060	0
Total operating expenses	2,520	1,427	3,967	2,775
Operating Income (Loss)	(472)	621	41	1,105
Other Income and (Expense):
Allowance for equity funds used during construction			32	25
Interest expense, net of amounts capitalized	(102)	(104)	(208)	(205)
Other income (expense), net	35	34	73	71
Total other income and (expense)	(67)	(70)	(135)	(134)
Earnings (Loss) Before Income Taxes	(539)	551	(94)	971
Income taxes (benefit)	(143)	199	(50)	355
Consolidated Net Income (Loss)	(396)	352	(44)	616
Less:
Dividends on preferred and preference stock of subsidiaries	0	5	0	9
Net Income (Loss)	(396)	347	(44)	607
GULF POWER CO
Operating Revenues:
Retail electric revenues	301	318	591	596
Wholesale revenues, non-affiliates	13	12	26	30
Wholesale revenues, affiliates	14	10	42	47
Other revenues	16	17	33	34
Total operating revenues	344	357	692	707
Operating Expenses:
Fuel	91	88	173	196
Purchased power, non-affiliates	44	44	90	78
Other operations and maintenance	90	90	166	176
Depreciation and amortization	48	35	95	53
Taxes other than income taxes	28	28	58	55
Loss on Plant Scherer Unit 3	0	0	0	33
Total operating expenses	301	285	582	591
Operating Income (Loss)	43	72	110	116
Other Income and (Expense):
Interest expense, net of amounts capitalized	(13)	(13)	(26)	(24)
Other income (expense), net	1	2	3	3
Total other income and (expense)	(12)	(11)	(23)	(21)
Earnings (Loss) Before Income Taxes	31	61	87	95
Income taxes (benefit)	(11)	24	3	38
Consolidated Net Income (Loss)	42	37	84	57
Less:
Dividends on preferred and preference stock of subsidiaries	0	2	0	4
Net Income (Loss)	42	35	84	53
MISSISSIPPI POWER CO
Operating Revenues:
Retail electric revenues	212	222	406	422
Wholesale revenues, non-affiliates	55	62	118	124
Wholesale revenues, affiliates	19	15	54	20
Other revenues	11	4	20	9
Total operating revenues	297	303	598	575
Operating Expenses:
Fuel	98	102	197	180
Purchased power, non-affiliates	7	6	16	14
Other operations and maintenance	67	72	141	148
Depreciation and amortization	44	41	84	81
Taxes other than income taxes	27	26	54	52
Estimated loss on plants under construction	0	3,012	45	3,120
Total operating expenses	243	3,259	537	3,595
Operating Income (Loss)	54	(2,956)	61	(3,020)
Other Income and (Expense):
Allowance for equity funds used during construction	0	36	0	71
Interest expense, net of amounts capitalized	(21)	(17)	(39)	(37)
Other income (expense), net	27	3	27	5
Total other income and (expense)	6	22	(12)	39
Earnings (Loss) Before Income Taxes	60	(2,934)	49	(2,981)
Income taxes (benefit)	13	(881)	9	(908)
Consolidated Net Income (Loss)	47	(2,053)	40	(2,073)
Less:
Dividends on preferred and preference stock of subsidiaries	1	1	1	1
Net Income (Loss)	46	(2,054)	39	(2,074)
SOUTHERN POWER CO
Operating Revenues:
Wholesale revenues, non-affiliates	443	436	867	783
Wholesale revenues, affiliates	109	90	192	190
Other revenues	3	3	5	6
Total operating revenues	555	529	1,064	979
Operating Expenses:
Fuel	153	139	321	271
Purchased power, non-affiliates	39	40	100	70
Other operations and maintenance	91	97	184	190
Depreciation and amortization	125	129	240	247
Taxes other than income taxes	12	12	24	24
Asset impairment	119	0	119	0
Total operating expenses	539	417	988	802
Operating Income (Loss)	16	112	76	177
Other Income and (Expense):
Interest expense, net of amounts capitalized	(46)	(48)	(93)	(97)
Other income (expense), net	2	2	5	(2)
Total other income and (expense)	(44)	(46)	(88)	(99)
Earnings (Loss) Before Income Taxes	(28)	66	(12)	78
Income taxes (benefit)	(73)	(38)	(172)	(90)
Consolidated Net Income (Loss)	45	104	160	168
Less:
Net income attributable to noncontrolling interests	23	22	17	17
Net Income (Loss)	22	82	143	151
SOUTHERN Co GAS
Operating Revenues:
Natural gas revenues (includes alternative revenue programs of $(4), $-, $(27), and $9, respectively)	710	684	2,341	2,205
Alternative revenue programs	(4)	0	(27)	9
Other revenues	24	32	55	62
Total operating revenues	730	716	2,369	2,276
Operating Expenses:
Cost of natural gas	228	232	949	951
Cost of other sales	5	6	12	13
Other operations and maintenance	238	214	514	470
Depreciation and amortization	126	125	255	244
Taxes other than income taxes	48	44	125	114
Goodwill impairment	0	0	42	0
Loss on disposition	36	0	36	0
Total operating expenses	681	621	1,933	1,792
Operating Income (Loss)	49	95	436	484
Other Income and (Expense):
Earnings from equity method investments	31	29	74	68
Interest expense, net of amounts capitalized	(59)	(48)	(118)	(94)
Other income (expense), net	3	4	15	10
Total other income and (expense)	(25)	(15)	(29)	(16)
Earnings (Loss) Before Income Taxes	24	80	407	468
Income taxes (benefit)	55	31	159	180
Consolidated Net Income (Loss)	(31)	49	248	288
Less:
Net Income (Loss)	$ (31)	$ 49	$ 248	$ 288

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Condensed Consolidated Statements of Income (Unaudited) (Parenthetical) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Alternative revenue programs	$ (4)	$ 0	$ (27)	$ 9
SOUTHERN Co GAS
Alternative revenue programs	(4)	0	(27)	9
Excise taxes collected	$ 23	$ 19	$ 74	$ 67

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Condensed Consolidated Statements of Comprehensive Income (Unaudited) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Net income (loss)	$ (127)	$ (1,348)	$ 809	$ (684)
Qualifying hedges:
Changes in fair value, net of tax	(54)	38	(8)	29
Reclassification adjustment for amounts included in net income, net of tax	64	(41)	45	(42)
Pension and other postretirement benefit plans:
Reclassification adjustment for amounts included in net income, net of tax	2	1	4	2
Total other comprehensive income (loss)	12	(2)	41	(11)
Comprehensive Income (Loss)	(115)	(1,350)	850	(695)
Less:
Dividends on preferred and preference stock of subsidiaries	4	11	8	22
Comprehensive income attributable to noncontrolling interests	23	22	17	17
Comprehensive Income (Loss) Attributable to Parent	(142)	(1,383)	825	(734)
ALABAMA POWER CO
Net income (loss)	262	235	491	412
Qualifying hedges:
Reclassification adjustment for amounts included in net income, net of tax	1	1	2	2
Pension and other postretirement benefit plans:
Total other comprehensive income (loss)	1	1	2	2
Comprehensive Income (Loss)	263	236	493	414
Less:
Dividends on preferred and preference stock of subsidiaries	3	5	7	9
GEORGIA POWER CO
Net income (loss)	(396)	352	(44)	616
Qualifying hedges:
Reclassification adjustment for amounts included in net income, net of tax	1	1	2	2
Pension and other postretirement benefit plans:
Total other comprehensive income (loss)	1	1	2	2
Comprehensive Income (Loss)	(395)	353	(42)	618
Less:
Dividends on preferred and preference stock of subsidiaries	0	5	0	9
GULF POWER CO
Net income (loss)	42	37	84	57
Qualifying hedges:
Changes in fair value, net of tax	0	(1)	0	(1)
Pension and other postretirement benefit plans:
Total other comprehensive income (loss)	0	(1)	0	(1)
Comprehensive Income (Loss)	42	36	84	56
Less:
Dividends on preferred and preference stock of subsidiaries	0	2	0	4
MISSISSIPPI POWER CO
Net income (loss)	47	(2,053)	40	(2,073)
Qualifying hedges:
Changes in fair value, net of tax	0	0	(1)	1
Reclassification adjustment for amounts included in net income, net of tax	0	0	1	0
Pension and other postretirement benefit plans:
Total other comprehensive income (loss)	0	0	0	1
Comprehensive Income (Loss)	47	(2,053)	40	(2,072)
Less:
Dividends on preferred and preference stock of subsidiaries	1	1	1	1
SOUTHERN POWER CO
Net income (loss)	45	104	160	168
Qualifying hedges:
Changes in fair value, net of tax	(55)	40	(8)	32
Reclassification adjustment for amounts included in net income, net of tax	59	(45)	35	(48)
Pension and other postretirement benefit plans:
Reclassification adjustment for amounts included in net income, net of tax	0	0	1	0
Total other comprehensive income (loss)	4	(5)	28	(16)
Comprehensive Income (Loss)	49	99	188	152
Less:
Comprehensive income attributable to noncontrolling interests	23	22	17	17
Comprehensive Income (Loss) Attributable to Parent	26	77	171	135
SOUTHERN Co GAS
Net income (loss)	(31)	49	248	288
Qualifying hedges:
Changes in fair value, net of tax	1	(1)	1	(2)
Reclassification adjustment for amounts included in net income, net of tax	0	0	2	0
Pension and other postretirement benefit plans:
Reclassification adjustment for amounts included in net income, net of tax	0	0	0	(1)
Total other comprehensive income (loss)	1	(1)	3	(3)
Comprehensive Income (Loss)	$ (30)	$ 48	$ 251	$ 285

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Condensed Consolidated Statements of Comprehensive Income (Unaudited) (Parenthetical) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Changes in fair value, tax	$ (18)	$ 23	$ (3)	$ 17
Reclassification adjustment for cash flow hedge, gain (loss), tax	21	(25)	15	(26)
Reclassification adjustment for pension and other post retirement benefit plans, tax	1	1	1	1
ALABAMA POWER CO
Reclassification adjustment for cash flow hedge, gain (loss), tax	0	1	1	1
GEORGIA POWER CO
Reclassification adjustment for cash flow hedge, gain (loss), tax	0	0	1	1
GULF POWER CO
Changes in fair value, tax	0	0	0	(1)
MISSISSIPPI POWER CO
Changes in fair value, tax	0	0	(1)	0
Reclassification adjustment for cash flow hedge, gain (loss), tax	0	0	0	0
SOUTHERN POWER CO
Changes in fair value, tax	(19)	24	(3)	20
Reclassification adjustment for cash flow hedge, gain (loss), tax	20	(27)	12	(30)
Reclassification adjustment for pension and other post retirement benefit plans, tax	0	0	0	0
SOUTHERN Co GAS
Changes in fair value, tax	0	(1)	0	(2)
Reclassification adjustment for cash flow hedge, gain (loss), tax	0	0	1	0
Reclassification adjustment for pension and other post retirement benefit plans, tax	$ 0	$ 0	$ 0	$ 0

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Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017
Operating Activities:
Net income (loss)	$ 809	$ (684)
Adjustments to reconcile consolidated net income (loss) to net cash provided from operating activities —
Depreciation and amortization, total	1,750	1,683
Deferred income taxes	(338)	(270)
Allowance for equity funds used during construction	(63)	(115)
Pension, postretirement, and other employee benefits	(74)	(83)
Settlement of asset retirement obligations	(97)	(87)
Stock based compensation expense	83	73
Estimated loss on plants under construction	1,088	3,120
Goodwill impairment	42
Asset impairment	161	0
Other, net	5	(118)
Changes in certain current assets and liabilities —
-Receivables	94	107
-Prepayments	(73)	(61)
-Natural gas for sale, net of temporary LIFO liquidation	295	223
-Other current assets	(40)	(30)
-Accounts payable	(406)	(353)
-Accrued taxes	213	(132)
-Accrued compensation	(284)	(331)
-Retail fuel cost over recovery	10	(187)
-Other current liabilities	125	(14)
Net cash provided from operating activities	3,258	2,741
Investing Activities:
Business acquisitions, net of cash acquired	(64)	(1,046)
Property additions	(3,828)	(3,398)
Nuclear decommissioning trust fund purchases	(571)	(388)
Nuclear decommissioning trust fund sales	566	383
Cost of removal, net of salvage	(128)	(128)
Change in construction payables, net	49	(117)
Investment in unconsolidated subsidiaries	(63)	(116)
Payments pursuant to LTSAs	(103)	(132)
Asset dispositions	500	65
Other investing activities	18	(6)
Net cash used for investing activities	(3,624)	(4,883)
Financing Activities:
Increase (decrease) in notes payable, net	1,442	30
Proceeds —
Long-term debt	1,100	2,958
Short-term borrowings	1,650	1,004
Common stock	222	417
Redemptions and repurchases —
Long-term debt	(3,379)	(1,478)
Preferred and preference stock	0	(150)
Short-term borrowings	(550)	0
Distributions to noncontrolling interests	(42)	(40)
Capital contributions from noncontrolling interests	1,210	73
Payment of common stock dividends	(1,194)	(1,134)
Other financing activities	(223)	(75)
Net cash provided from financing activities	236	1,605
Net Change in Cash, Cash Equivalents, and Restricted Cash	(130)	(537)
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	2,147	1,992
Cash, Cash Equivalents, and Restricted Cash at End of Period	2,017	1,455
Cash paid (received) during the period for —
Interest	927	833
Income taxes, net	4	1
Noncash transactions — Accrued property additions at end of period	1,067	629
ALABAMA POWER CO
Operating Activities:
Net income (loss)	491	412
Adjustments to reconcile consolidated net income (loss) to net cash provided from operating activities —
Depreciation and amortization, total	452	442
Deferred income taxes	48	192
Allowance for equity funds used during construction	(27)	(16)
Pension, postretirement, and other employee benefits	(28)	(24)
Other, net	(40)	20
Changes in certain current assets and liabilities —
-Receivables	(153)	(58)
-Prepayments	(57)	(56)
-Materials and supplies	(47)	(18)
-Other current assets	29	12
-Accounts payable	(196)	(154)
-Accrued taxes	134	52
-Accrued compensation	(70)	(74)
-Retail fuel cost over recovery	0	(65)
-Other current liabilities	116	7
Net cash provided from operating activities	652	672
Investing Activities:
Property additions	(997)	(738)
Nuclear decommissioning trust fund purchases	(131)	(117)
Nuclear decommissioning trust fund sales	131	117
Cost of removal, net of salvage	(34)	(54)
Change in construction payables, net	(29)	48
Other investing activities	(15)	(15)
Net cash used for investing activities	(1,075)	(759)
Proceeds —
Senior notes	500	550
Capital contributions from parent company	488	327
Redemptions and repurchases —
Senior notes	0	(200)
Payment of common stock dividends	(402)	(357)
Other financing activities	(21)	(14)
Net cash provided from financing activities	565	306
Net Change in Cash, Cash Equivalents, and Restricted Cash	142	219
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	544	420
Cash, Cash Equivalents, and Restricted Cash at End of Period	686	639
Cash paid (received) during the period for —
Interest	143	140
Income taxes, net	17	88
Noncash transactions — Accrued property additions at end of period	216	132
GEORGIA POWER CO
Operating Activities:
Net income (loss)	(44)	616
Adjustments to reconcile consolidated net income (loss) to net cash provided from operating activities —
Depreciation and amortization, total	562	543
Deferred income taxes	(256)	159
Allowance for equity funds used during construction	(32)	(25)
Deferred expenses	34	41
Pension, postretirement, and other employee benefits	(47)	(45)
Settlement of asset retirement obligations	(49)	(62)
Other, net	27	(39)
Changes in certain current assets and liabilities —
-Receivables	(103)	(150)
-Fossil fuel stock	38	(32)
-Prepaid income taxes	115	(4)
-Other current assets	25	(18)
-Accounts payable	(87)	(153)
-Accrued taxes	(89)	(194)
-Accrued compensation	(56)	(65)
-Retail fuel cost over recovery	0	(84)
-Other current liabilities	(26)	(6)
Net cash provided from operating activities	1,072	482
Investing Activities:
Property additions	(1,501)	(1,284)
Nuclear decommissioning trust fund purchases	(440)	(271)
Nuclear decommissioning trust fund sales	435	266
Cost of removal, net of salvage	(50)	(32)
Change in construction payables, net of joint owner portion	86	1
Payments pursuant to LTSAs	(46)	(56)
Asset dispositions	134	63
Other investing activities	(11)	(12)
Net cash used for investing activities	(1,393)	(1,325)
Financing Activities:
Increase (decrease) in notes payable, net	480	37
Proceeds —
Senior notes	0	850
Short-term borrowings	0	800
Capital contributions from parent company	1,502	380
Redemptions and repurchases —
Senior notes	(1,000)	(450)
Pollution control revenue bonds	(398)	(27)
Other long-term debt	(100)	0
Short-term borrowings	(150)	0
Payment of common stock dividends	(691)	(640)
Premiums on redemption and repurchases of senior notes	(152)	0
Other financing activities	(11)	(19)
Net cash provided from financing activities	(520)	931
Net Change in Cash, Cash Equivalents, and Restricted Cash	(841)	88
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	852	3
Cash, Cash Equivalents, and Restricted Cash at End of Period	11	91
Cash paid (received) during the period for —
Interest	211	186
Income taxes, net	64	213
Noncash transactions — Accrued property additions at end of period	669	348
GULF POWER CO
Operating Activities:
Net income (loss)	84	57
Adjustments to reconcile consolidated net income (loss) to net cash provided from operating activities —
Depreciation and amortization, total	98	56
Deferred income taxes	(21)	19
Loss on Plant Scherer Unit 3	0	33
Other, net	(3)	(3)
Changes in certain current assets and liabilities —
-Receivables	9	(25)
-Other current assets	(2)	14
-Accounts payable	(16)	3
-Accrued taxes	18	7
-Accrued compensation	(15)	(17)
-Over recovered regulatory clause revenues	5	(19)
-Other current liabilities	0	(1)
Net cash provided from operating activities	157	124
Investing Activities:
Property additions	(135)	(97)
Cost of removal, net of salvage	(14)	(9)
Change in construction payables, net	(3)	(14)
Other investing activities	(6)	(3)
Net cash used for investing activities	(158)	(123)
Financing Activities:
Increase (decrease) in notes payable, net	45	(190)
Proceeds —
Senior notes	0	300
Capital contributions from parent company	37	5
Common stock	0	175
Redemptions and repurchases —
Preferred and preference stock	0	(150)
Senior notes	0	(85)
Payment of common stock dividends	(77)	(63)
Other financing activities	(1)	(4)
Net cash provided from financing activities	4	(12)
Net Change in Cash, Cash Equivalents, and Restricted Cash	3	(11)
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	28	56
Cash, Cash Equivalents, and Restricted Cash at End of Period	31	45
Cash paid (received) during the period for —
Interest	25	22
Income taxes, net	21	7
Noncash transactions — Accrued property additions at end of period	22	19
MISSISSIPPI POWER CO
Operating Activities:
Net income (loss)	40	(2,073)
Adjustments to reconcile consolidated net income (loss) to net cash provided from operating activities —
Depreciation and amortization, total	86	94
Deferred income taxes	289	(860)
Allowance for equity funds used during construction	0	(71)
Estimated loss on plants under construction	28	3,120
Other, net	(13)	(11)
Changes in certain current assets and liabilities —
-Receivables	(51)	(15)
-Fossil fuel stock	(2)	21
-Other current assets	(9)	(10)
-Accounts payable	(15)	(20)
-Accrued taxes	(41)	0
-Accrued compensation	(14)	(17)
-Over recovered regulatory clause revenues	10	(30)
-Other current liabilities	(11)	7
Net cash provided from operating activities	297	135
Investing Activities:
Property additions	(74)	(337)
Change in construction payables, net	(9)	(19)
Payments pursuant to LTSAs	(13)	3
Other investing activities	(12)	(8)
Net cash used for investing activities	(108)	(361)
Financing Activities:
Increase (decrease) in notes payable, net	(4)	(10)
Proceeds —
Senior notes	600	0
Short-term borrowings	300	4
Capital contributions from parent company	1	1,001
Long-term debt to parent company	0	(40)
Redemptions and repurchases —
Other long-term debt	(900)	(300)
Short-term borrowings	(200)	0
Long-term debt to parent company	0	(591)
Other financing activities	(6)	(2)
Net cash provided from financing activities	(209)	142
Net Change in Cash, Cash Equivalents, and Restricted Cash	(20)	(84)
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	248	224
Cash, Cash Equivalents, and Restricted Cash at End of Period	228	140
Cash paid (received) during the period for —
Interest	39	26
Income taxes, net	(257)	(93)
Noncash transactions — Accrued property additions at end of period	23	59
SOUTHERN POWER CO
Operating Activities:
Net income (loss)	160	168
Adjustments to reconcile consolidated net income (loss) to net cash provided from operating activities —
Depreciation and amortization, total	256	264
Deferred income taxes	(252)	91
Amortization of investment tax credits	(29)	(28)
Deferred revenues	(19)	(34)
Income taxes receivable, non-current	(4)	(58)
Asset impairment	119	0
Other, net	13	(1)
Changes in certain current assets and liabilities —
-Receivables	(30)	(58)
-Prepaid income taxes	(36)	33
-Other current assets	3	20
-Accounts payable	(41)	(45)
-Accrued taxes	15	4
-Other current liabilities	(28)	(8)
Net cash provided from operating activities	127	348
Investing Activities:
Business acquisitions, net of cash acquired	(64)	(1,004)
Property additions	(198)	(145)
Change in construction payables, net	2	(167)
Payments pursuant to LTSAs	(32)	(68)
Other investing activities	15	(3)
Net cash used for investing activities	(277)	(1,387)
Financing Activities:
Increase (decrease) in notes payable, net	(41)	189
Proceeds —
Short-term borrowings	200	0
Capital contributions from parent company	16	0
Redemptions and repurchases —
Return of paid in capital	(250)	0
Senior notes	(350)	0
Other long-term debt	(420)	(3)
Distributions to noncontrolling interests	(42)	(40)
Capital contributions from noncontrolling interests	1,210	73
Payment of common stock dividends	(156)	(158)
Other financing activities	(15)	(18)
Net cash provided from financing activities	152	43
Net Change in Cash, Cash Equivalents, and Restricted Cash	2	(996)
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	140	1,112
Cash, Cash Equivalents, and Restricted Cash at End of Period	142	116
Cash paid (received) during the period for —
Interest	109	113
Income taxes, net	109	(117)
Noncash transactions — Accrued property additions at end of period	33	19
SOUTHERN Co GAS
Operating Activities:
Net income (loss)	248	288
Adjustments to reconcile consolidated net income (loss) to net cash provided from operating activities —
Depreciation and amortization, total	255	244
Deferred income taxes	(12)	144
Mark-to-market adjustments	2	(49)
Goodwill impairment	42	0
Loss on disposition	36	0
Other, net	(24)	(34)
Changes in certain current assets and liabilities —
-Receivables	504	418
-Natural gas for sale, net of temporary LIFO liquidation	295	223
-Prepaid income taxes	9	24
-Other current assets	32	(12)
-Accounts payable	(125)	(102)
-Accrued taxes	38	(8)
-Accrued compensation	(6)	(12)
-Other current liabilities	24	25
Net cash provided from operating activities	1,318	1,149
Investing Activities:
Property additions	(679)	(684)
Cost of removal, net of salvage	(18)	(25)
Change in construction payables, net	(6)	23
Investment in unconsolidated subsidiaries	(60)	(111)
Asset dispositions	364	0
Other investing activities	18	18
Net cash used for investing activities	(381)	(779)
Financing Activities:
Increase (decrease) in notes payable, net	(515)	(631)
Proceeds —
Senior notes	0	450
Capital contributions from parent company	10	57
Redemptions and repurchases —
Long-term debt	(200)	0
Payment of common stock dividends	(235)	(221)
Other financing activities	0	(6)
Net cash provided from financing activities	(940)	(351)
Net Change in Cash, Cash Equivalents, and Restricted Cash	(3)	19
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	78	24
Cash, Cash Equivalents, and Restricted Cash at End of Period	75	43
Cash paid (received) during the period for —
Interest	129	105
Income taxes, net	106	20
Noncash transactions — Accrued property additions at end of period	$ 129	$ 84

XML

Condensed Consolidated Statements of Cash Flows (Unaudited) (Parenthetical) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017
Net cash paid for capitalized interest	$ 35	$ 55
ALABAMA POWER CO
Net cash paid for capitalized interest	10	6
GEORGIA POWER CO
Net cash paid for capitalized interest	12	11
GULF POWER CO
Net cash paid for capitalized interest	0	0
MISSISSIPPI POWER CO
Interest paid	39	53
Net cash paid for capitalized interest	0	27
SOUTHERN POWER CO
Net cash paid for capitalized interest	10	4
SOUTHERN Co GAS
Net cash paid for capitalized interest	$ 3	$ 7

XML

Condensed Consolidated Balance Sheets (Unaudited) - USD ($) $ in Millions	Jun. 30, 2018	Dec. 31, 2017
Current Assets:
Cash and cash equivalents	$ 1,980	$ 2,130
Receivables —
Customer accounts receivable	1,728	1,806
Energy marketing receivables	451	607
Unbilled revenues	769	810
Under recovered fuel clause revenues	159	171
Other accounts and notes receivable	621	698
Accumulated provision for uncollectible accounts	(42)	(44)
Materials and supplies	1,397	1,438
Fossil fuel for generation	462	594
Natural gas for sale	292	595
Prepaid expenses	398	452
Other regulatory assets, current	528	604
Assets held for sale, current	2,704	12
Other current assets	172	199
Total current assets	11,619	10,072
Property, Plant, and Equipment:
In service	99,626	103,542
Less: Accumulated depreciation	30,255	31,457
Plant in service, net of depreciation	69,371	72,085
Nuclear fuel, at amortized cost	874	883
Construction work in progress	6,947	6,904
Total property, plant, and equipment	77,192	79,872
Other Property and Investments:
Goodwill	5,315	6,268
Equity investments in unconsolidated subsidiaries	1,546	1,513
Other intangible assets, net of amortization	702	873
Nuclear decommissioning trusts, at fair value	1,829	1,832
Leveraged leases	788	775
Miscellaneous property and investments	247	249
Total other property and investments	10,427	11,510
Deferred Charges and Other Assets:
Deferred charges related to income taxes	789	825
Unamortized loss on reacquired debt	333	206
Other regulatory assets, deferred	6,302	6,943
Assets held for sale	4,618	0
Other deferred charges and assets	1,497	1,577
Total deferred charges and other assets	13,539	9,551
Total Assets	112,777	111,005
Current Liabilities:
Securities due within one year	2,237	3,892
Notes payable	4,981	2,439
Energy marketing trade payables	485	546
Accounts payable —
Accounts payable	2,162	2,530
Customer deposits	488	542
Accrued taxes —
Accrued taxes	544	636
Accrued interest	469	488
Accrued compensation	646	959
Asset retirement obligations, current	332	351
Other regulatory liabilities, current	508	337
Liabilities held for sale, current	706	0
Other current liabilities	808	874
Total current liabilities	14,366	13,594
Long-term Debt	42,483	44,462
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	5,934	6,842
Deferred credits related to income taxes	6,647	7,256
Accumulated deferred ITCs	2,360	2,267
Employee benefit obligations	2,009	2,256
Asset retirement obligations, deferred	5,836	4,473
Accrued environmental remediation	273	389
Other cost of removal obligations	2,364	2,684
Other regulatory liabilities, deferred	140	239
Liabilities held for sale	2,833	0
Other deferred credits and liabilities	516	691
Total deferred credits and other liabilities	28,912	27,097
Total Liabilities	85,761	85,153
Redeemable Preferred Stock of Subsidiaries	324	324
Common Stockholders' Equity:
Common stock	5,066	5,038
Paid-in capital	10,303	10,469
Treasury, at cost	(39)	(36)
Retained earnings (accumulated deficit)	8,494	8,885
Accumulated other comprehensive income (loss)	(188)	(189)
Total Common Stockholders' Equity	23,636	24,167
Noncontrolling interests	3,056	1,361
Total stockholders' equity	26,692	25,528
Total Liabilities and Stockholders' Equity	112,777	111,005
ALABAMA POWER CO
Current Assets:
Cash and cash equivalents	686	544
Receivables —
Customer accounts receivable	401	355
Unbilled revenues	174	162
Under recovered fuel clause revenues	28	0
Other accounts and notes receivable	41	55
Affiliated	54	43
Accumulated provision for uncollectible accounts	(10)	(9)
Materials and supplies	518	458
Fossil fuel for generation	154	184
Prepaid expenses	90	85
Other regulatory assets, current	146	124
Other current assets	11	5
Total current assets	2,293	2,006
Property, Plant, and Equipment:
In service	29,374	27,326
Less: Accumulated depreciation	9,813	9,563
Plant in service, net of depreciation	19,561	17,763
Nuclear fuel, at amortized cost	337	339
Construction work in progress	1,172	908
Total property, plant, and equipment	21,070	19,010
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	66	67
Nuclear decommissioning trusts, at fair value	906	903
Miscellaneous property and investments	124	124
Total other property and investments	1,096	1,094
Deferred Charges and Other Assets:
Deferred charges related to income taxes	234	239
Deferred under recovered regulatory clause revenues	121	54
Other regulatory assets, deferred	1,244	1,272
Other deferred charges and assets	212	189
Total deferred charges and other assets	1,811	1,754
Total Assets	26,270	23,864
Current Liabilities:
Securities due within one year	200	0
Accounts payable —
Affiliated	298	327
Other	398	585
Customer deposits	95	92
Accrued taxes —
Accrued taxes	137	54
Accrued interest	81	77
Accrued compensation	140	205
Other regulatory liabilities, current	118	1
Other current liabilities	143	59
Total current liabilities	1,610	1,400
Long-term Debt	7,922	7,628
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	2,829	2,760
Deferred credits related to income taxes	2,061	2,082
Accumulated deferred ITCs	109	112
Employee benefit obligations	275	304
Asset retirement obligations, deferred	3,085	1,702
Other cost of removal obligations	580	609
Other regulatory liabilities, deferred	43	84
Other deferred credits and liabilities	64	63
Total deferred credits and other liabilities	9,046	7,716
Total Liabilities	18,578	16,744
Redeemable Preferred Stock	291	291
Common Stockholders' Equity:
Common stock	1,222	1,222
Paid-in capital	3,480	2,986
Retained earnings (accumulated deficit)	2,729	2,647
Accumulated other comprehensive income (loss)	(30)	(26)
Total Common Stockholders' Equity	7,401	6,829
Total Liabilities and Stockholders' Equity	26,270	23,864
GEORGIA POWER CO
Current Assets:
Cash and cash equivalents	11	852
Receivables —
Customer accounts receivable	631	544
Unbilled revenues	276	255
Under recovered fuel clause revenues	159	165
Joint owner accounts receivable	239	262
Other accounts and notes receivable	81	76
Affiliated	25	24
Accumulated provision for uncollectible accounts	(3)	(3)
Materials and supplies	498	504
Fossil fuel for generation	276	314
Prepaid expenses	91	216
Other regulatory assets, current	206	205
Other current assets	23	14
Total current assets	2,513	3,428
Property, Plant, and Equipment:
In service	35,467	34,861
Less: Accumulated depreciation	11,901	11,704
Plant in service, net of depreciation	23,566	23,157
Nuclear fuel, at amortized cost	536	544
Construction work in progress	4,157	4,613
Total property, plant, and equipment	28,259	28,314
Other Property and Investments:
Equity investments in unconsolidated subsidiaries	52	53
Nuclear decommissioning trusts, at fair value	924	929
Miscellaneous property and investments	61	59
Total other property and investments	1,037	1,041
Deferred Charges and Other Assets:
Deferred charges related to income taxes	518	516
Other regulatory assets, deferred	3,064	2,932
Other deferred charges and assets	570	548
Total deferred charges and other assets	4,152	3,996
Total Assets	35,961	36,779
Current Liabilities:
Securities due within one year	509	857
Notes payable	480	150
Accounts payable —
Affiliated	458	493
Other	885	834
Customer deposits	275	270
Accrued taxes —
Accrued taxes	230	344
Accrued interest	110	123
Accrued compensation	149	219
Asset retirement obligations, current	191	270
Other regulatory liabilities, current	214	191
Other current liabilities	205	198
Total current liabilities	3,706	3,949
Long-term Debt	9,936	11,073
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	2,925	3,175
Deferred credits related to income taxes	3,218	3,248
Accumulated deferred ITCs	267	248
Employee benefit obligations	636	659
Asset retirement obligations, deferred	2,427	2,368
Other deferred credits and liabilities	144	128
Total deferred credits and other liabilities	9,617	9,826
Total Liabilities	23,259	24,848
Common Stockholders' Equity:
Common stock	398	398
Paid-in capital	8,834	7,328
Retained earnings (accumulated deficit)	3,480	4,215
Accumulated other comprehensive income (loss)	(10)	(10)
Total Common Stockholders' Equity	12,702	11,931
Total Liabilities and Stockholders' Equity	35,961	36,779
GULF POWER CO
Current Assets:
Cash and cash equivalents	31	28
Receivables —
Customer accounts receivable	87	76
Unbilled revenues	71	67
Under recovered fuel clause revenues	3	27
Other accounts and notes receivable	5	7
Affiliated	15	14
Accumulated provision for uncollectible accounts	(1)	(1)
Materials and supplies	61	57
Fossil fuel for generation	63	63
Other regulatory assets, current	49	56
Other current assets	19	21
Total current assets	403	415
Property, Plant, and Equipment:
In service	5,293	5,196
Less: Accumulated depreciation	1,523	1,461
Plant in service, net of depreciation	3,770	3,735
Construction work in progress	116	91
Total property, plant, and equipment	3,886	3,826
Deferred Charges and Other Assets:
Deferred charges related to income taxes	30	31
Other regulatory assets, deferred	486	502
Other deferred charges and assets	36	23
Total deferred charges and other assets	552	556
Total Assets	4,841	4,797
Current Liabilities:
Notes payable	90	45
Accounts payable —
Affiliated	51	52
Other	57	75
Customer deposits	35	35
Accrued taxes —
Accrued taxes	28	10
Accrued interest	8	9
Accrued compensation	24	39
Deferred capacity expense, current	22	22
Asset retirement obligations, current	39	37
Other regulatory liabilities, current	54	0
Other current liabilities	24	27
Total current liabilities	432	351
Long-term Debt	1,285	1,285
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	540	537
Deferred credits related to income taxes	384	458
Employee benefit obligations	98	102
Deferred capacity expense	86	97
Asset retirement obligations, deferred	109	105
Other cost of removal obligations	216	221
Other regulatory liabilities, deferred	52	43
Other deferred credits and liabilities	64	67
Total deferred credits and other liabilities	1,549	1,630
Total Liabilities	3,266	3,266
Common Stockholders' Equity:
Common stock	678	678
Paid-in capital	632	594
Retained earnings (accumulated deficit)	266	259
Accumulated other comprehensive income (loss)	(1)	0
Total Common Stockholders' Equity	1,575	1,531
Total Liabilities and Stockholders' Equity	4,841	4,797
MISSISSIPPI POWER CO
Current Assets:
Cash and cash equivalents	228	248
Receivables —
Customer accounts receivable	37	36
Unbilled revenues	42	41
Income taxes receivable, current	37	4
Other accounts and notes receivable	24	12
Affiliated	21	16
Materials and supplies	50	44
Fossil fuel for generation	19	17
Other regulatory assets, current	121	125
Other current assets	9	9
Total current assets	588	552
Property, Plant, and Equipment:
In service	4,816	4,773
Less: Accumulated depreciation	1,365	1,325
Plant in service, net of depreciation	3,451	3,448
Construction work in progress	88	84
Total property, plant, and equipment	3,539	3,532
Other Property and Investments:
Total other property and investments	25	30
Deferred Charges and Other Assets:
Deferred charges related to income taxes	34	35
Other regulatory assets, deferred	448	437
Accumulated deferred income taxes	0	247
Other deferred charges and assets	19	33
Total deferred charges and other assets	501	752
Total Assets	4,653	4,866
Current Liabilities:
Securities due within one year	257	989
Notes payable	100	4
Accounts payable —
Affiliated	53	59
Other	62	96
Accrued taxes —
Accrued income taxes	0	40
Accrued taxes	51	101
Accrued compensation	25	39
Accrued plant closure costs	42	35
Asset retirement obligations, current	41	37
Other current liabilities	74	63
Total current liabilities	705	1,463
Long-term Debt	1,522	1,097
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	60	0
Deferred credits related to income taxes	415	372
Employee benefit obligations	112	116
Asset retirement obligations, deferred	135	137
Other cost of removal obligations	179	178
Other regulatory liabilities, deferred	78	79
Other deferred credits and liabilities	16	33
Total deferred credits and other liabilities	995	915
Total Liabilities	3,222	3,475
Redeemable Preferred Stock	33	33
Common Stockholders' Equity:
Common stock	38	38
Paid-in capital	4,531	4,529
Retained earnings (accumulated deficit)	(3,166)	(3,205)
Accumulated other comprehensive income (loss)	(5)	(4)
Total Common Stockholders' Equity	1,398	1,358
Total Liabilities and Stockholders' Equity	4,653	4,866
SOUTHERN POWER CO
Current Assets:
Cash and cash equivalents	142	129
Receivables —
Customer accounts receivable	165	117
Other accounts and notes receivable	63	98
Affiliated	60	50
Materials and supplies	213	278
Prepaid income taxes	82	50
Assets held for sale, current	17	1
Other current assets	31	35
Total current assets	773	758
Property, Plant, and Equipment:
In service	13,402	13,755
Less: Accumulated depreciation	1,959	1,910
Plant in service, net of depreciation	11,443	11,845
Construction work in progress	771	511
Total property, plant, and equipment	12,214	12,356
Other Property and Investments:
Intangible assets, net (including goodwill)	398	411
Total other property and investments	398	411
Deferred Charges and Other Assets:
Prepaid LTSAs	93	118
Accumulated deferred income taxes	1,223	925
Income taxes receivable, non-current	81	72
Assets held for sale	183	0
Other deferred charges and assets	463	566
Total deferred charges and other assets	2,043	1,681
Total Assets	15,428	15,206
Current Liabilities:
Securities due within one year	0	770
Notes payable	264	105
Accounts payable —
Affiliated	75	102
Other	84	103
Accrued taxes —
Liabilities held for sale, current	2	0
Other current liabilities	146	152
Total current liabilities	571	1,232
Long-term Debt	5,037	5,071
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	135	199
Accumulated deferred ITCs	1,856	1,884
Other deferred credits and liabilities	255	322
Total deferred credits and other liabilities	2,246	2,405
Total Liabilities	7,854	8,708
Common Stockholders' Equity:
Common stock	0	0
Paid-in capital	3,023	3,662
Retained earnings (accumulated deficit)	1,464	1,478
Accumulated other comprehensive income (loss)	31	(2)
Total Common Stockholders' Equity	4,518	5,138
Noncontrolling interests	3,056	1,360
Total stockholders' equity	7,574	6,498
Total Liabilities and Stockholders' Equity	15,428	15,206
SOUTHERN Co GAS
Current Assets:
Cash and cash equivalents	69	73
Receivables —
Customer accounts receivable	243	400
Energy marketing receivables	451	607
Unbilled revenues	60	285
Other accounts and notes receivable	53	103
Accumulated provision for uncollectible accounts	(26)	(28)
Natural gas for sale	292	595
Prepaid expenses	64	53
Assets from risk management activities, net of collateral	93	135
Other regulatory assets, current	55	94
Assets held for sale, current	2,298	0
Other current assets	42	78
Total current assets	3,694	2,395
Property, Plant, and Equipment:
In service	14,504	15,833
Less: Accumulated depreciation	4,293	4,596
Plant in service, net of depreciation	10,211	11,237
Construction work in progress	571	491
Total property, plant, and equipment	10,782	11,728
Other Property and Investments:
Goodwill	5,015	5,967
Equity investments in unconsolidated subsidiaries	1,507	1,477
Other intangible assets, net of amortization	125	280
Miscellaneous property and investments	20	21
Total other property and investments	6,667	7,745
Deferred Charges and Other Assets:
Other regulatory assets, deferred	742	901
Other deferred charges and assets	227	218
Total deferred charges and other assets	969	1,119
Total Assets	22,112	22,987
Current Liabilities:
Securities due within one year	156	157
Notes payable	1,003	1,518
Energy marketing trade payables	485	546
Accounts payable —
Accounts payable	359	446
Customer deposits	101	128
Accrued taxes —
Accrued income taxes	86	40
Accrued taxes	63	78
Accrued interest	53	51
Accrued compensation	61	74
Liabilities from risk management activities, net of collateral	21	69
Other regulatory liabilities, current	162	135
Liabilities held for sale, current	412	0
Other current liabilities	143	159
Total current liabilities	3,105	3,401
Long-term Debt	5,667	5,891
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	1,026	1,089
Deferred credits related to income taxes	920	1,063
Employee benefit obligations	389	415
Accrued environmental remediation	273	342
Other cost of removal obligations	1,575	1,646
Other deferred credits and liabilities	96	118
Total deferred credits and other liabilities	4,279	4,673
Total Liabilities	13,051	13,965
Common Stockholders' Equity:
Common stock	0	0
Paid-in capital	9,236	9,214
Retained earnings (accumulated deficit)	(202)	(212)
Accumulated other comprehensive income (loss)	27	20
Total Common Stockholders' Equity	9,061	9,022
Total Liabilities and Stockholders' Equity	$ 22,112	$ 22,987

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Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) - USD ($) $ in Millions	Jun. 30, 2018	Dec. 31, 2017
Other intangible assets, accumulated amortization	$ 205	$ 186
Common stock, par value (in dollars per share)	$ 5	$ 5
Common stock, shares authorized (in shares)	1,500,000,000.0	1,500,000,000.0
Common stock, shares issued (in shares)	1,000,000,000	1,000,000,000
Treasury shares at cost (in shares)	1,000,000	900,000
ALABAMA POWER CO
Common stock, par value (in dollars per share)	$ 40	$ 40
Common stock, shares authorized (in shares)	40,000,000	40,000,000
Common stock, shares outstanding (in shares)	30,537,500	30,537,500
GEORGIA POWER CO
Common stock, shares authorized (in shares)	20,000,000	20,000,000
Common stock, shares outstanding (in shares)	9,261,500	9,261,500
GULF POWER CO
Common stock, shares authorized (in shares)	20,000,000	20,000,000
Common stock, shares outstanding (in shares)	7,392,717	7,392,717
MISSISSIPPI POWER CO
Common stock, shares authorized (in shares)	1,130,000	1,130,000
Common stock, shares outstanding (in shares)	1,121,000	1,121,000
SOUTHERN POWER CO
Other intangible assets, accumulated amortization	$ 60	$ 47
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	1,000,000	1,000,000
Common stock, shares outstanding (in shares)	1,000	1,000
SOUTHERN Co GAS
Other intangible assets, accumulated amortization	$ 121	$ 120
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	100,000,000	100,000,000
Common stock, shares outstanding (in shares)	100	100

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Introduction

6 Months Ended

Jun. 30, 2018

Organization, Consolidation and Presentation of Financial Statements [Abstract]

INTRODUCTION

INTRODUCTION

The condensed quarterly financial statements of each registrant included herein have been prepared by such registrant, without audit, pursuant to the rules and regulations of the SEC. The Condensed Balance Sheets as of December 31, 2017 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, 2018 and 2017. 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 Adopted Accounting Standards

See Note 1 to the financial statements of the registrants under "Recently Issued Accounting Standards" in Item 8 of the Form 10-K for additional information.

Revenue

In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry-specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. ASC 606 became effective on January 1, 2018 and the registrants adopted it using the modified retrospective method applied to open contracts and only to the version of the contracts in effect as of January 1, 2018. In accordance with the modified retrospective method, the registrants' previously issued financial statements have not been restated to comply with ASC 606 and the registrants did not have a cumulative-effect adjustment to retained earnings. The adoption of ASC 606 had no significant impact on the timing of revenue recognition compared to previously reported results; however, it requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers, which are included in Note (C).

ASC 606 provided additional clarity on financial statement presentation that resulted in reclassifications into other revenues and other operations and maintenance from other income/(expense), net at Alabama Power and Georgia Power related to certain unregulated sales of products and services. In addition, contract assets related to Southern Company's unregulated distributed generation business have been reclassified from unbilled revenue in accordance with the guidance in ASC 606. These reclassifications did not affect the timing or amount of revenues recognized or cash flows. ASC 606 also provided additional guidance on over-time revenue recognition, resulting in a change in the timing of revenue recognized from guaranteed and fixed billing arrangements at Southern Company Gas. The changes in natural gas revenues recognized in the second quarter and year-to-date 2018 relate primarily to the seasonal nature of natural gas usage.

The net impact of accounting for revenue under ASC 606 decreased Southern Company's consolidated net income by $5 million for the three months ended June 30, 2018 and increased Southern Company's consolidated net income by $5 million for the six months ended June 30, 2018.

The specific impacts of applying ASC 606 to revenues from contracts with customers on the financial statements of Southern Company, Alabama Power, Georgia Power, and Southern Company Gas compared to previously recognized guidance is shown below.

	For the Three Months Ended June 30, 2018									For the Six Months Ended June 30, 2018
Condensed Statements of Income	As Reported			Balances Without Adoption of ASC 606			Effect of Change			As Reported			Balances Without Adoption of ASC 606			Effect of Change
	(in millions)									(in millions)
Southern Company
Natural gas revenues	$	706		$	713		$	(7	)	$	2,314		$	2,307		$	7
Other revenues	395			393			2			808			805			3
Other operations and maintenance	1,559			1,546			13			3,008			2,985			23
Operating income	63			81			(18		)	1,439			1,452			(13		)
Other income (expense), net	78			67			11			138			118			20
Earnings (loss) before income taxes	(266		)	(259		)	(7		)	784			777			7
Income taxes (benefit)	(139		)	(137		)	(2		)	(25		)	(27		)	2
Consolidated net income (loss)	(127		)	(122		)	(5		)	809			804			5
Consolidated net income (loss) attributable to Southern Company	(154		)	(149		)	(5		)	784			779			5
Alabama Power
Other revenues	$	69		$	60		$	9		$	131		$	114		$	17
Other operations and maintenance	402			391			11			788			767			21
Operating income	380			382			(2		)	752			756			(4		)
Other income (expense), net	12			10			2			15			11			4
Georgia Power
Other revenues	$	120		$	97		$	23		$	227		$	189		$	38
Other operations and maintenance	457			437			20			863			828			35
Operating income (loss)	(472		)	(475		)	3			41			38			3
Other income (expense), net	35			38			(3		)	73			76			(3		)
Southern Company Gas
Natural gas revenues	$	710		$	717		$	(7	)	$	2,341		$	2,334		$	7
Operating income	49			56			(7		)	436			429			7
Earnings before income taxes	24			31			(7		)	407			400			7
Income taxes	55			57			(2		)	159			157			2
Net income (loss)	(31		)	(26		)	(5		)	248			243			5

	For the Six Months Ended June 30, 2018
Condensed Statements of Cash Flows	As Reported			Balances Without Adoption of ASC 606			Effect of Change
	(in millions)
Southern Company
Consolidated net income	$	809		$	804		$	5
Changes in certain current assets and liabilities:
Receivables	94			99			(5		)
Other current assets	(40		)	(45		)	5
Accrued taxes	213			215			(2		)
Other current liabilities	125			118			7
Georgia Power
Changes in certain current assets and liabilities:
Receivables	$	(103	)	$	(75	)	$	(28	)
Other current assets	25			(3		)	28
Southern Company Gas
Net income	$	248		$	243		$	5
Changes in certain current assets and liabilities:
Accrued taxes	38			40			(2		)
Other current liabilities	24			17			7

	At June 30, 2018
Condensed Balance Sheets	As Reported			Balances Without Adoption of ASC 606			Effect of Change
	(in millions)
Southern Company
Unbilled revenues	$	769		$	824		$	(55	)
Other accounts and notes receivable	621			622			(1		)
Other current assets	172			116			56
Accrued taxes	544			542			2
Other current liabilities	808			815			(7		)
Retained earnings	8,494			8,489			5
Southern Company Gas
Accrued income taxes	$	86		$	84		$	2
Other current liabilities	143			150			(7		)
Accumulated deficit	(202		)	(207		)	5

Other

In 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (ASU 2016-18). ASU 2016-18 eliminates the need to reflect transfers between cash and restricted cash in operating, investing, and financing activities in the statements of cash flows. In addition, the net change in cash and cash equivalents during the period includes amounts generally described as restricted cash or restricted cash equivalents. The registrants adopted ASU 2016-18 effective January 1, 2018 with no material impact on their financial statements. Southern Company, Southern Power, and Southern Company Gas retrospectively applied ASU 2016-18 effective January 1, 2018 and have restated prior periods in the statements of cash flows by immaterial amounts. The change in restricted cash in the statements of cash flows was previously disclosed in operating activities for Southern Company and Southern Company Gas and in investing activities for Southern Company and Southern Power. See "Restricted Cash" herein for additional information.

In March 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in the statements of income outside of income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. The registrants adopted ASU 2017-07 effective January 1, 2018 with no material impact on their financial statements. ASU 2017-07 has been applied retrospectively for the presentation of the service cost component and the other components of net periodic benefit costs in the statements of income for Southern Company, the traditional electric operating companies, and Southern Company Gas. Since Southern Power did not participate in the qualified pension and postretirement benefit plans until December 2017, no retrospective presentation of Southern Power's net periodic benefits costs is required. The requirement to limit capitalization to the service cost component of net periodic benefit costs has been applied on a prospective basis from the date of adoption for all registrants. The presentation changes resulted in a decrease in operating income and an increase in other income for the three and six months ended June 30, 2018 and 2017 for Southern Company, the traditional electric operating companies, and Southern Company Gas.

In August 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12). ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The registrants adopted ASU 2017-12 effective January 1, 2018 with no material impact on their financial statements. See Note (I) for disclosures required by ASU 2017-12.

On February 14, 2018, the FASB issued ASU No. 2018-02, Income Statement – Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income (ASU 2018-02) to address the application of ASC 740, Income Taxes (ASC 740) to certain provisions of the Tax Reform Legislation. ASU 2018-02 specifically addresses the ASC 740 requirement that the effect of a change in tax laws or rates on deferred tax assets and liabilities be included in income from continuing operations, even when the tax effects were initially recognized directly in OCI at the previous rate, which strands the income tax rate differential in accumulated OCI. The amendments in ASU 2018-02 allow a reclassification from accumulated OCI to retained earnings for stranded tax effects resulting from the Tax Reform Legislation. The registrants adopted ASU 2018-02 effective January 1, 2018 with no material impact on their financial statements.

Asset Retirement Obligations

See Note 1 to the financial statements of Southern Company and the traditional electric operating companies under "Asset Retirement Obligations and Other Costs of Removal" in Item 8 of the Form 10-K for additional information regarding each company's AROs and the EPA's Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule).

As of June 30, 2018, details of the AROs, including those related to the CCR Rule, included in the condensed balance sheets of Southern Company, Alabama Power, and Mississippi Power were as follows:

	Southern Company			Alabama Power			Mississippi Power
	(in millions)
Balance at December 31, 2017	$	4,824		$	1,709		$	174
Liabilities incurred	1			—			—
Liabilities settled	(97		)	(19		)	(15		)
Accretion	95			41			2
Cash flow revisions	1,493			1,451			15
Reclassification to held for sale	(148		)	—			—
Balance at June 30, 2018	$	6,168		$	3,182		$	176

In June 2018, Alabama Power recorded an increase of approximately $1.2 billion to its AROs related to the CCR Rule. The revised cost estimates as of June 30, 2018 are based on information from feasibility studies performed on ash ponds in use at plants operated by Alabama Power, including a plant jointly-owned by Mississippi Power. During the second quarter 2018, Alabama Power's management completed its analysis of these studies which indicated that additional closure costs, primarily related to increases in estimated ash volume, water management requirements, and design revisions, will be required to close these ash ponds under the planned closure-in-place methodology. As a result of these revised cost estimates, in June 2018, Mississippi Power recorded an increase of approximately $11 million to its AROs related to an ash pond at the plant jointly-owned with Alabama Power.

Georgia Power continues to perform engineering studies related to its plans to close the ash ponds at all of its generating plants, including one jointly owned with Gulf Power, in compliance with federal and state CCR rules. Georgia Power also continues to refine its closure strategy and cost estimates for each ash pond and is preparing permit applications as required by the State of Georgia CCR rule. While each of Georgia Power and Gulf Power believes its recorded liability for ash pond closures appropriately reflects its obligations under the current closure strategies it has elected, changes to such strategies and cost estimates would likely result in additional closure costs which would increase each of Georgia Power's and Gulf Power's ARO liability. It is not currently possible to determine the magnitude of an increase related to a change in closure strategies nor an increase related to ongoing engineering studies for the current closure strategies, and the timing of future cash outflows are indeterminable at this time. As permit applications advance, engineering studies continue, and the timing of ash pond closures develop further on a plant-by-plant basis during the second half of 2018 and in the future, Georgia Power will record any changes as necessary to its ARO liability, which could be material. Georgia Power expects to continue to periodically update these cost estimates as necessary, which could change further as additional information becomes available. Gulf Power will record any incremental AROs, which could be material, related to its share of Plant Scherer Unit 3, which is co-owned with Georgia Power, once Georgia Power further refines its cost estimate of the impact on its ARO liability.

As further analysis is performed and closure details are developed with respect to ash pond closures, the traditional electric operating companies expect to periodically update their cost estimates as necessary. Absent continued recovery of ARO costs through regulated rates, Southern Company's and the traditional electric operating companies' results of operations, cash flows, and financial condition could be materially impacted. The ultimate outcome of this matter cannot be determined at this time.

In June 2018, Alabama Power completed an updated decommissioning cost site study for Plant Farley. The estimated cost of decommissioning based on the study resulted in an increase in Southern Company's and Alabama Power's ARO liability of approximately $300 million. See "Nuclear Decommissioning" below for additional information.

The reclassification of a portion of the ARO liability to liabilities held for sale by Southern Company represents the AROs related to Gulf Power. See Note (J) under "Southern Company's Sale of Gulf Power" and "Assets Held for Sale" for additional information.

Nuclear Decommissioning

See Note 1 to the financial statements of Southern Company and Alabama Power under "Nuclear Decommissioning" in Item 8 of the Form 10-K for additional information.

In June 2018, Alabama Power completed an updated decommissioning cost site study for Plant Farley. The estimated costs of decommissioning based on the 2018 site study are as follows:

Decommissioning periods:
Beginning year	2037
Completion year	2076
	(in millions)
Site study costs:
Radiated structures	$	1,621
Non-radiated structures	99
Total site study costs	$	1,720

The decommissioning cost estimates are based on prompt dismantlement and removal of the plant from service. The actual decommissioning costs may vary from the above estimates because of changes in the assumed date of decommissioning, changes in NRC requirements, or changes in the assumptions used in making these estimates.

For ratemaking purposes, Alabama Power's decommissioning costs are based on the site study. Significant assumptions used to determine these costs for ratemaking were an inflation rate of 4.5% and a trust earnings rate of 7.0%. The next site study is expected to be completed in 2023.

Amounts previously contributed to the external trust funds are currently projected to be adequate to meet the updated decommissioning obligations. Alabama Power will continue to provide site specific estimates of the decommissioning costs and related projections of funds in the external trust to the Alabama PSC and, if necessary, would seek the Alabama PSC's approval to address any changes in a manner consistent with the NRC and other applicable requirements.

Goodwill and Other Intangible Assets

The following table presents year-to-date changes in goodwill balances for Southern Company and Southern Company Gas:

	Goodwill
	Southern Company				Southern Company Gas
					Gas Distribution Operations			Gas Marketing Services			Total
	(in millions)
Balance at December 31, 2017	$	6,268			$	4,702		$	1,265		$	5,967
Impairment(a)	(42		)		—			(42		)	(42		)
Sale of Pivotal Home Solutions(a)	(242		)		—			(242		)	(242		)
Reclassification to held for sale(b)	(668		)		(668		)	—			(668		)
Balance at June 30, 2018	$	5,315		(c)	$	4,034		$	981		$	5,015

(a) On April 11, 2018, Southern Company Gas entered into a stock purchase agreement for the sale of Pivotal Home Solutions. In contemplation of the transaction, a goodwill impairment charge of $42 million was recorded in the first quarter 2018. On June 4, 2018, Southern Company Gas and Pivotal Home Solutions completed this transaction. See Note (J) under "Southern Company Gas" for additional information.

(b) Reflects goodwill associated with Elizabethtown Gas, Elkton Gas, and Florida City Gas, which were sold subsequent to June 30, 2018. See Note (J) under "Southern Company Gas" and "Assets Held for Sale" for additional information.

(c) Total does not add due to rounding.

Goodwill is not amortized but is subject to an annual impairment test during the fourth quarter of each year or more frequently if impairment indicators arise.

Other intangible assets were as follows:

	At June 30, 2018							At December 31, 2017
	Gross Carrying Amount		Accumulated Amortization			Other Intangible Assets, Net		Gross Carrying Amount		Accumulated Amortization			Other Intangible Assets, Net
	(in millions)							(in millions)
Southern Company
Other intangible assets subject to amortization:
Customer relationships(*)	$	223	$	(79	)	$	144	$	288	$	(83	)	$	205
Trade names(*)	70		(17		)	53		159		(17		)	142
Storage and transportation contracts	64		(44		)	20		64		(34		)	30
PPA fair value adjustments	456		(60		)	396		456		(47		)	409
Other	19		(5		)	14		17		(5		)	12
Total other intangible assets subject to amortization	$	832	$	(205	)	$	627	$	984	$	(186	)	$	798
Other intangible assets not subject to amortization:
Federal Communications Commission licenses	75		—			75		75		—			75
Total other intangible assets	$	907	$	(205	)	$	702	$	1,059	$	(186	)	$	873
Southern Power
Other intangible assets subject to amortization:
PPA fair value adjustments	$	456	$	(60	)	$	396	$	456	$	(47	)	$	409
Southern Company Gas
Other intangible assets subject to amortization:
Gas marketing services(*)
Customer relationships	$	156	$	(71	)	$	85	$	221	$	(77	)	$	144
Trade names	26		(6		)	20		115		(9		)	106
Wholesale gas services
Storage and transportation contracts	64		(44		)	20		64		(34		)	30
Total other intangible assets subject to amortization	$	246	$	(121	)	$	125	$	400	$	(120	)	$	280

(*) Balances as of June 30, 2018 reflect Southern Company Gas' sale of Pivotal Home Solutions. See Note (J) under "Southern Company Gas – Sale of Pivotal Home Solutions" for additional information.

Amortization associated with other intangible assets was as follows:

	Three Months Ended		Six Months Ended
	June 30, 2018
	(in millions)
Southern Company	$	23	$	50
Southern Power	$	6	$	13
Southern Company Gas	$	14	$	31

Restricted Cash

The registrants adopted ASU 2016-18 as of January 1, 2018. See "Recently Adopted Accounting Standards – Other" herein for additional information.

At December 31, 2017, Southern Power had restricted cash primarily related to certain acquisitions and construction projects. At both June 30, 2018 and December 31, 2017, Southern Company Gas had restricted cash held as collateral for worker's compensation, life insurance, and long-term disability insurance.

The following tables provide a reconciliation of cash, cash equivalents, and restricted cash reported within the condensed balance sheets that total to the amounts shown in the condensed statements of cash flows for the registrants that had restricted cash at June 30, 2018 and/or December 31, 2017:

	Southern Company		Southern Company Gas
	(in millions)
At June 30, 2018
Cash and cash equivalents	$	1,980	$	69
Cash and cash equivalents classified as assets held for sale	31		—
Restricted cash:
Other accounts and notes receivable	6		6
Total cash, cash equivalents, and restricted cash	$	2,017	$	75

	Southern Company		Southern Power		Southern Company Gas
	(in millions)
At December 31, 2017
Cash and cash equivalents	$	2,130	$	129	$	73
Restricted cash:
Other accounts and notes receivable	5		—		5
Deferred charges and other assets	12		11		—
Total cash, cash equivalents, and restricted cash	$	2,147	$	140	$	78

Natural Gas for Sale

Southern Company Gas' natural gas distribution utilities, with the exception of Nicor Gas, carry natural gas inventory on a WACOG basis.

Nicor Gas' natural gas inventory is carried at cost on a LIFO basis. Inventory decrements occurring during the year that are restored prior to year end are charged to cost of natural gas at the estimated annual replacement cost. Inventory decrements that are not restored prior to year end are charged to cost of natural gas at the actual LIFO cost of the inventory layers liquidated. Southern Company Gas' inventory decrement at June 30, 2018 is expected to be restored prior to year end. The cost of natural gas, including inventory costs, is recovered from customers under a purchased gas recovery mechanism adjusted for differences between actual costs and amounts billed; therefore, LIFO liquidations have no impact on Southern Company's or Southern Company Gas' net income.

Natural gas inventories for Southern Company Gas' non-utility businesses are carried at the lower of weighted average cost or current market price, with cost determined on a WACOG basis. For any declines in market prices below the WACOG considered to be other than temporary, an adjustment is recorded to reduce the value of natural gas inventories to market value. Southern Company Gas had no material LOCOM adjustment in any period presented.

Hypothetical Liquidation at Book Value

Southern Power has consolidated renewable generation projects that are partially funded by a third-party tax equity investor. The related contractual provisions represent profit-sharing arrangements because the allocations of cash distributions and tax benefits are not based on fixed ownership percentages. Therefore, the noncontrolling interest is accounted for under a balance sheet approach utilizing the hypothetical liquidation at book value (HLBV) method. The HLBV method calculates each partner's share of income based on the change in net equity the partner can legally claim in a hypothetical liquidation at the end of the period compared to the beginning of the period.

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Contingencies and Regulatory Matters

6 Months Ended

Jun. 30, 2018

Commitments and Contingencies Disclosure [Abstract]

CONTINGENCIES AND REGULATORY MATTERS

CONTINGENCIES AND REGULATORY MATTERS

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

General Litigation Matters

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

The ultimate outcome of such pending or potential litigation against each registrant and any subsidiaries cannot be predicted at this time; however, for current proceedings not specifically reported herein, 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.

Southern Company

In January 2017, a putative securities class action complaint was filed against Southern Company, certain of its officers, and certain former Mississippi Power officers in the U.S. District Court for the Northern District of Georgia, Atlanta Division, by Monroe County Employees' Retirement System on behalf of all persons who purchased shares of Southern Company's common stock between April 25, 2012 and October 29, 2013. The complaint alleges that Southern Company, certain of its officers, and certain former Mississippi Power officers made materially false and misleading statements regarding the Kemper County energy facility in violation of certain provisions under the Securities Exchange Act of 1934, as amended. The complaint seeks, among other things, compensatory damages and litigation costs and attorneys' fees. In June 2017, the plaintiffs filed an amended complaint that provided additional detail about their claims, increased the purported class period by one day, and added certain other former Mississippi Power officers as defendants. In July 2017, the defendants filed a motion to dismiss the plaintiffs' amended complaint with prejudice, to which the plaintiffs filed an opposition in September 2017. On March 29, 2018, the U.S. District Court for the Northern District of Georgia, Atlanta Division, issued an order granting, in part, the defendants' motion to dismiss. The court dismissed certain claims against certain officers of Southern Company and Mississippi Power and dismissed the allegations related to a number of the statements that plaintiffs challenged as being false or misleading. On April 26, 2018, the defendants filed a motion for reconsideration of the court's order, seeking dismissal of the remaining claims in the lawsuit.

In February 2017, Jean Vineyard filed a shareholder derivative lawsuit and, in May 2017, Judy Mesirov filed a shareholder derivative lawsuit, each in the U.S. District Court for the Northern District of Georgia. Each of these lawsuits names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. In August 2017, these two shareholder derivative lawsuits were consolidated in the U.S. District Court for the Northern District of Georgia. The complaints allege that the defendants caused Southern Company to make false or misleading statements regarding the Kemper County energy facility cost and schedule. Further, the complaints allege that the defendants were unjustly enriched and caused the waste of corporate assets and also allege that the individual defendants violated their fiduciary duties. Each plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and, on each plaintiff's own behalf, attorneys' fees and costs in bringing the lawsuit. Each plaintiff also seeks certain changes to Southern Company's corporate governance and internal processes. On April 25, 2018, the court entered an order staying this lawsuit until 30 days after the resolution of any dispositive motions or any settlement, whichever is earlier, in the putative securities class action.

In May 2017, Helen E. Piper Survivor's Trust filed a shareholder derivative lawsuit in the Superior Court of Gwinnett County, State of Georgia that names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. The complaint alleges that the individual defendants, among other things, breached their fiduciary duties in connection with schedule delays and cost overruns associated with the construction of the Kemper County energy facility. The complaint further alleges that the individual defendants authorized or failed to correct false and misleading statements regarding the Kemper County energy facility schedule and cost and failed to implement necessary internal controls to prevent harm to Southern Company. The plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and disgorgement of profits and, on its behalf, attorneys' fees and costs in bringing the lawsuit. The plaintiff also seeks certain unspecified changes to Southern Company's corporate governance and internal processes. The court entered an order staying this lawsuit until 30 days after the resolution of any dispositive motions or any settlement, whichever is earlier, in the putative securities class action.

Southern Company believes these legal challenges have no merit; however, an adverse outcome in any of 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, the ultimate outcome of which cannot be determined at this time.

Alabama Power

On March 2, 2018, the Alabama Department of Environmental Management (ADEM) issued proposed administrative orders assessing a penalty of $1.25 million to Alabama Power for unpermitted discharge of fluids and/or pollutants to groundwater at five electric generating plants. The proposed orders also require the submission to the ADEM of a plan with a schedule for implementation of a comprehensive groundwater investigation, including an assessment of corrective measures, a report evaluating any deficiencies at the facilities that may have led to the unpermitted discharges, and quarterly progress reports. Alabama Power is awaiting finalization of the orders. The ultimate outcome of this matter cannot be determined at this time.

Georgia Power

In 2011, plaintiffs filed a putative class action against Georgia Power in the Superior Court of Fulton County, Georgia alleging that Georgia Power's collection in rates of municipal franchise fees (all of which are remitted to municipalities) exceeded the amounts allowed in orders of the Georgia PSC and alleging certain state tort law claims. In 2016, the Georgia Court of Appeals reversed the trial court's previous dismissal of the case and remanded the case to the trial court. Georgia Power filed a petition for writ of certiorari with the Georgia Supreme Court, which was granted in August 2017. On June 18, 2018, the Georgia Supreme Court affirmed the judgment of the Georgia Court of Appeals and the case has been remanded to the trial court for further proceedings. Georgia Power believes the plaintiffs' claims have no merit and intends to vigorously defend itself in this matter. The amount of any possible losses cannot be calculated at this time because, among other factors, it is unknown whether any class will ultimately be certified; the scope of such a class, if certified; and whether any losses would be subject to recovery from any municipalities. The ultimate outcome of this matter cannot be determined at this time.

Mississippi Power

In 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 to include, among other things, Southern Company as a defendant. The individual plaintiff alleged that Mississippi Power and Southern Company violated the Mississippi Unfair Trade Practices Act. All plaintiffs 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 County energy facility and that these alleged breaches unjustly enriched Mississippi Power and Southern Company. The plaintiffs sought unspecified actual damages and punitive damages; asked the Circuit Court to appoint a receiver to oversee, operate, manage, and otherwise control all affairs relating to the Kemper County energy facility; asked the Circuit Court to revoke any licenses or certificates authorizing Mississippi Power or Southern Company to engage in any business related to the Kemper County energy facility in Mississippi; and sought attorney's fees, costs, and interest. The plaintiffs also sought an injunction to prevent any Kemper County energy facility costs from being charged to customers through electric rates. In June 2017, the Circuit Court ruled in favor of motions by Southern Company and Mississippi Power and dismissed the case. In July 2017, the plaintiffs filed notice of an appeal. On July 13, 2018, Mississippi Power and Southern Company reached a settlement agreement with the plaintiffs and the plaintiffs' appeal was dismissed with prejudice. The settlement had no material impact on Southern Company's or Mississippi Power's financial statements.

On May 18, 2018, Southern Company and Mississippi Power received a notice of dispute and arbitration demand filed by Martin Product Sales, LLC (Martin) based on two agreements, both related to Kemper IGCC byproducts for which Mississippi Power provided termination notices in September 2017. Martin alleges breach of contract, breach of good faith and fair dealing, fraud and misrepresentation, and civil conspiracy and makes a claim for damages in the amount of approximately $143 million, as well as additional unspecified damages, attorney's fees, costs, and interest. Southern Company and Mississippi Power believe this legal challenge has no merit; however, an adverse outcome in this proceeding could have a material impact on Southern Company's and Mississippi Power's results of operations, financial condition, and liquidity. Southern Company and Mississippi Power will vigorously defend themselves in this matter, the ultimate outcome of which cannot be determined at this time.

On May 14, 2018, Mississippi Power's claim for lost revenue resulting from the Deepwater Horizon oil spill in the Gulf of Mexico in 2010 was settled. The settlement proceeds of $18 million, net of expenses and income tax, are included in Southern Company's and Mississippi Power's earnings for the second quarter 2018.

Southern Power

Southern Power indirectly owns a 51% membership interest in RE Roserock LLC (Roserock), the owner of the Roserock facility in Pecos County, Texas. Prior to the facility being placed in service in November 2016, certain solar panels were damaged during installation by the construction contractor, McCarthy Building Companies, Inc. (McCarthy), and certain solar panels were damaged by a hail event that also occurred during construction. In May 2017, Roserock filed a lawsuit in the state district court in Pecos County, Texas, (State Court lawsuit) against XL Insurance America, Inc. (XL) and North American Elite Insurance Company (North American Elite) seeking recovery from an insurance policy for damages resulting from the hail storm and McCarthy's installation practices. On June 1, 2018, the court in the State Court lawsuit granted Roserock's motion for partial summary judgment, finding that the insurers were in breach of contract and in violation of the Texas Insurance Code for failing to pay any monies owed for the hail claim. Roserock is working to distinguish its damages between those attributable to the hail event versus damages attributable to installation. In addition to the State Court lawsuit, lawsuits were filed between Roserock and McCarthy, as well as other parties, and that litigation has been consolidated in the U.S. District Court for the Western District of Texas. Southern Power intends to vigorously pursue and defend these matters, the ultimate outcome of which cannot be determined at this time.

Southern Company Gas

Nicor Energy Services Company, doing business as Pivotal Home Solutions, formerly a wholly-owned subsidiary of Southern Company Gas, was a defendant in a putative class action initially filed in 2017 in the state court in Indiana. The plaintiffs purported to represent a class of the customers who purchased products from Nicor Energy Services Company and alleged that the marketing, sale, and billing of the products violated the Indiana Consumer Fraud and Deceptive Business Practices Act, constituting common law fraud and resulting in unjust enrichment of these entities. In 2018, Nicor Energy Services Company was named in a second class action filed in the state court of Ohio asserting nearly identical allegations and legal claims. The plaintiffs sought, on behalf of the classes they purported to represent, actual and punitive damages, interest costs, attorney fees, and injunctive relief. To facilitate the sale of Pivotal Home Solutions, Southern Company Gas retained most of the financial responsibility for these lawsuits following the completion of the sale. On June 12, 2018, the parties settled these claims and Southern Company Gas recorded an $11 million charge, which is reflected in other operations and maintenance expenses on the statements of income.

Environmental Matters

Environmental Remediation

The Southern Company system must comply with environmental laws and regulations governing 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 and the natural gas distribution utilities in Illinois, New Jersey, Georgia, and Florida have all received authority from their respective state PSCs or other applicable state regulatory agencies to recover approved environmental compliance costs through regulatory mechanisms. These regulatory mechanisms are adjusted annually or as necessary within limits approved by the state PSCs or other applicable state regulatory agencies.

Georgia Power's environmental remediation liability was $25 million and $22 million as of June 30, 2018 and December 31, 2017, respectively. Georgia Power has been designated or identified as a potentially responsible party at sites governed by the Georgia Hazardous Site Response Act and/or by the federal Comprehensive Environmental Response, Compensation, and Liability Act, and assessment and potential cleanup of such sites is expected.

Gulf Power's environmental remediation liability includes estimated costs of environmental remediation projects of approximately $48 million and $52 million as of June 30, 2018 and December 31, 2017, respectively. 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's substations. The schedule for completion of the remediation projects is subject to FDEP approval.

At June 30, 2018, Southern Company Gas' environmental remediation liability was $305 million based on the estimated cost of environmental investigation and remediation associated with known current and former manufactured gas plant operating sites, with an additional $77 million liability related to Elizabethtown Gas classified as held for sale. At December 31, 2017, Southern Company Gas' total environmental remediation liability was $388 million, of which $85 million related to Elizabethtown Gas. These environmental remediation expenditures are recoverable from customers through rate mechanisms approved by the applicable state regulatory agencies of the natural gas distribution utilities, with the exception of one site representing $2 million of the total accrued remediation costs. See Note (J) under "Southern Company Gas" and "Assets Held for Sale" for additional information.

The ultimate outcome of these matters cannot be determined at this time; however, as a result of the regulatory treatment for environmental remediation expenses described above, the final disposition of these matters is not expected to have a material impact on the financial statements of Southern Company, Georgia Power, Gulf Power, or Southern Company Gas.

FERC Matters

Market-Based Rate Authority

See Note 3 to the financial statements of Southern Company, the traditional electric operating companies, and Southern Power under "FERC Matters" in Item 8 of the Form 10-K for additional information regarding proceedings related to the traditional electric operating companies'and Southern Power's 2014 and 2017 triennial market power analyses.

On May 4, 2018, the FERC issued an order terminating both proceedings, finding that the traditional electric operating companiesand Southern Power satisfy the FERC's standards for market-based rates. On May 9, 2018, the traditional electric operating companiesand Southern Power made the compliance filing required by the order. These proceedings are essentially concluded.

Open Access Transmission Tariff

On May 10, 2018, the Alabama Municipal Electric Authority and Cooperative Energy filed with the FERC a complaint against SCS and the traditional electric operating companiesclaiming that the current11.25%base ROE used in calculating the annual transmission revenue requirements of the traditional electric operating companies'open access transmission tariff is unjust and unreasonable as measured by the applicable FERC standards. The complaint requests that the base ROE be set no higher than8.65%and that the FERC order refunds for the difference in revenue requirements that results from applying a just and reasonable ROE established in this proceeding upon determining the current ROE is unjust and unreasonable. On June 18, 2018, SCS and the traditional electric operating companiesfiled their response challenging the adequacy of the showing presented by the complainants and offering support for the current ROE. The ultimate outcome of this matter cannot be determined at this time.

Cooperative Energy Power Supply Agreement

See Note 3 to the financial statements of Mississippi Power under "FERC Matters – Cooperative Energy Power Supply Agreement" in Item 8 of the Form 10-K for additional information regarding Cooperative Energy's network integration transmission service agreement (NITSA) with SCS.

On March 23, 2018, the FERC accepted the amendment to the NITSA between Cooperative Energy and SCS, effective April 1, 2018.

Regulatory Matters

Alabama Power

See Note 3 to the financial statements of Southern Company and Alabama Power under "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, 2018		December 31, 2017
		(in millions)
Rate CNP Compliance	Deferred under recovered regulatory clause revenues	$	30	$	17
Rate CNP PPA	Deferred under recovered regulatory clause revenues	11		12
Retail Energy Cost Recovery	Deferred under recovered regulatory clause revenues	80		25
	Under recovered regulatory clause revenues	28		—
Natural Disaster Reserve	Other regulatory liabilities, deferred	30		38

On May 1, 2018, the Alabama PSC approved modifications to Rate RSE and other commitments designed to position Alabama Power to address the growing pressure on its credit quality resulting from the Tax Reform Legislation, without increasing retail rates under Rate RSE in the near term. Alabama Power plans to reduce growth in total debt by increasing equity, with corresponding reductions in debt issuances, thereby de-leveraging its capital structure. Alabama Power's goal is to achieve an equity ratio of approximately 55% by the end of 2025. At June 30, 2018, Alabama Power's equity ratio was approximately 46.6%.

Rate RSE

The approved modifications to Rate RSE became effective June 2018 and are applicable for January 2019 billings and thereafter. The modifications include reducing the top of the allowed weighted common equity return (WCER) range from 6.21% to 6.15% and modifications to the refund mechanism applicable to prior year actual results. The modifications to the refund mechanism allow Alabama Power to retain a portion of the revenue that causes the actual WCER for a given year to exceed the allowed range.

Generally, if Alabama Power's actual WCER range is between 6.15% and 7.65%, customers will receive 25% of the amount between 6.15% and 6.65%, 40% of the amount between 6.65% and 7.15%, and 75% of the amount between 7.15% and 7.65%. Customers will receive all amounts in excess of an actual WCER of 7.65%.

In conjunction with these modifications to Rate RSE, on May 8, 2018, Alabama Power consented to a moratorium on any upward adjustments under Rate RSE for 2019 and 2020. Additionally, Alabama Power will return $50 million to customers through bill credits in 2019.

In accordance with an established retail tariff that provides for an interim adjustment to customer billings to recognize the impact of a change in the statutory income tax rate, Alabama Power is returning approximately $257 million to retail customers through bill credits in the second half of 2018 as a result of the change in the federal income tax rate under the Tax Reform Legislation.

Rate ECR

On May 1, 2018, the Alabama PSC approved an increase to Rate ECR from 2.015 cents per KWH to 2.353 cents per KWH effective July 2018 which is expected to result in additional collections of approximately $100 million through December 31, 2018. The approved increase in the Rate ECR factor will have no significant effect on Alabama Power's net income, but will increase operating cash flows related to fuel cost recovery in 2018. The rate will return to 5.910 cents per KWH in 2019, absent a further order from the Alabama PSC.

Accounting Order

On May 1, 2018, the Alabama PSC approved an accounting order that authorizes Alabama Power to defer the benefits of federal excess deferred income taxes associated with the Tax Reform Legislation for the year ending December 31, 2018 as a regulatory liability and to use up to $30 million of such deferrals to offset under recovered amounts under Rate ECR. Any remaining amounts will be used for the benefit of customers as determined by the Alabama PSC. As of June 30, 2018, Alabama Power had applied approximately $30 million of such deferrals to offset the under recovered balance under Rate ECR and expects the total deferrals for the year ending December 31, 2018 to be approximately $50 million. See Note 5 to the financial statements of Southern Company and Alabama Power under "Federal Tax Reform Legislation" and of Alabama Power under "Current and Deferred Income Taxes" in Item 8 of the Form 10-K for additional information.

Plant Greene County

Alabama Power jointly owns Plant Greene County with an affiliate, Mississippi Power. See Note 4 to the financial statements of Alabama Power in Item 8 of the Form 10-K for additional information regarding the joint ownership agreement. On August 6, 2018, Mississippi Power filed its proposed Reserve Margin Plan (RMP) with the Mississippi PSC, which proposes a 4-year acceleration of the retirement of Plant Greene County Units 1 and 2 to the third quarter 2021 and the third quarter 2022, respectively. Mississippi Power's proposed Plant Greene County unit retirements would require the completion of proposed transmission and system reliability improvements, as well as agreement by Alabama Power. Alabama Power will monitor Mississippi Power's proposed RMP and associated regulatory process as well as the proposed transmission and system reliability improvements. Alabama Power will review all the facts and circumstances and will evaluate all its alternatives prior to reaching a final determination on the ongoing operations of Plant Greene County. The ultimate outcome of this matter cannot be determined at this time.

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 certified construction costs of Plant Vogtle Units 3 and 4 are being collected through the NCCR tariff and fuel costs are collected through a separate fuel cost recovery tariff. See "Nuclear Construction" herein and Note 3 to the financial statements of Southern Company under "Nuclear Construction" and Georgia Power under "Retail Regulatory Matters – Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding the NCCR tariff. Also see "Fuel Cost Recovery" herein and Note 3 to the financial statements of Southern Company under "Regulatory Matters – Georgia Power – Fuel Cost Recovery" and Georgia Power under "Retail Regulatory Matters – Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information regarding fuel cost recovery.

Rate Plans

See Note 3 to the financial statements of Southern Company and Georgia Power under "Regulatory Matters – Georgia Power – Rate Plans" and "Retail Regulatory Matters – Rate Plans," respectively, in Item 8 of the Form 10-K for additional information regarding Georgia Power's 2013 ARP and the Georgia PSC's 2018 order related to the Tax Reform Legislation.

On April 3, 2018, the Georgia PSC approved a settlement agreement between Georgia Power and the staff of the Georgia PSC regarding the retail rate impact of the Tax Reform Legislation (Georgia Power Tax Reform Settlement Agreement). Pursuant to the Georgia Power Tax Reform Settlement Agreement, to reflect the federal income tax rate reduction impact of the Tax Reform Legislation, Georgia Power will refund to customers a total of $330 million through bill credits of $131 million in October 2018, $96 million in June 2019, and $103 million in February 2020. In addition, Georgia Power is deferring as a regulatory liability (i) the revenue equivalent of the tax expense reduction resulting from legislation lowering the Georgia state income tax rate from 6.00% to 5.75% in 2019 and (ii) the entire benefit of approximately $700 million in federal and state excess accumulated deferred income taxes. The amortization of these regulatory liabilities is expected to be addressed in Georgia Power's next base rate case, which is scheduled to be filed by July 1, 2019. If there is not a base rate case in 2019, customers will receive $185 million in annual bill credits beginning in 2020, with any additional federal and state income tax savings deferred as a regulatory liability, until Georgia Power's next base rate case.

To address the negative cash flow and credit metric impacts of the Tax Reform Legislation, the Georgia PSC also approved an increase in Georgia Power's retail equity ratio to the lower of (i) Georgia Power's actual common equity weight in its capital structure or (ii) 55%, until Georgia Power's next base rate case. Benefits from reduced federal income tax rates in excess of the amounts refunded to customers will be retained by Georgia Power to cover the carrying costs of the incremental equity in 2018 and 2019.

Fuel Cost Recovery

As of June 30, 2018 and December 31, 2017, Georgia Power's under recovered fuel balance totaled $159 million and $165 million, respectively, and is included as under recovered fuel clause revenues on Southern Company's and Georgia Power's condensed balance sheets. The Georgia PSC will review Georgia Power's cumulative over or under recovered fuel balance no later than September 1, 2018 and evaluate the need to file a fuel case. Georgia Power continues to be allowed to adjust its fuel cost recovery rates under an interim fuel rider prior to the next fuel case if the under or over recovered fuel balance exceeds $200 million.

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.

Gulf Power

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 regarding Gulf Power's rates and charges for service to retail customers.

Retail Base Rate Case

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

As a continuation of a settlement agreement approved by the Florida PSC in April 2017 (2017 Gulf Power Rate Case Settlement Agreement), on March 26, 2018, the Florida PSC approved a stipulation and settlement agreement among Gulf Power and three intervenors addressing the retail revenue requirement effects of the Tax Reform Legislation (Gulf Power Tax Reform Settlement Agreement).

The Gulf Power Tax Reform Settlement Agreement results in annual reductions to Gulf Power's revenues of $18.2 million from base rates and $15.6 million from environmental cost recovery rates, implemented April 1, 2018, and also provides for a one-time refund of $69.4 million for the retail portion of unprotected (not subject to normalization) deferred tax liabilities through a reduced fuel cost recovery rate over the remainder of 2018. Through June 30, 2018, approximately $28 million of this refund has been reflected in customer bills. As a result of the Gulf Power Tax Reform Settlement Agreement, the Florida PSC also approved an increase in Gulf Power's maximum equity ratio from 52.5% to 53.5% for all retail regulatory purposes.

As part of the Gulf Power Tax Reform Settlement Agreement, a limited scope proceeding to address protected deferred tax liabilities consistent with IRS normalization principles was initiated on April 30, 2018. Pending resolution of this proceeding, Gulf Power is deferring the related amounts for 2018 as a regulatory liability. Through June 30, 2018, amounts deferred totaled $5 million. Unless otherwise agreed to by the parties to the Gulf Power Tax Reform Settlement Agreement, amounts recorded in this regulatory liability will be refunded to retail customers in 2019 through Gulf Power's fuel cost recovery rates. The ultimate outcome of this matter cannot be determined at this time.

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, as approved by the Florida PSC. Regulatory clause recovery balances included in the balance sheets are as follows:

Regulatory Clause	Balance Sheet Line Item	June 30, 2018		December 31, 2017
		(in millions)
Fuel Cost Recovery	Under recovered regulatory clause revenues	$	—	$	22
Fuel Cost Recovery	Other regulatory liabilities, current	5		—
Purchased Power Capacity Recovery	Under recovered regulatory clause revenues	2		2
Environmental Cost Recovery(*)	Under recovered regulatory clause revenues	1		2
Energy Conservation Cost Recovery	Other regulatory liabilities, current	1		—

(*) At June 30, 2018 and December 31, 2017, the under recovered balance included in the balance sheets represents the current portion of the regulatory assets associated with projected environmental expenditures of approximately $11 million and $13 million, respectively, partially offset by the over recovered environmental cost recovery balance of approximately $10 million and $11 million, respectively.

Mississippi Power

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

On May 8, 2018, the Mississippi PSC issued an order to begin an operations review of Mississippi Power in August 2018 with the final report expected by February 28, 2019. Mississippi Power expects that the review will include, but not be limited to, a comparative analysis of its costs, its cost recovery framework, and ways in which it may streamline management operations for the reasonable benefit of ratepayers. The ultimate outcome of this matter cannot be determined at this time.

Performance Evaluation Plan

In each of 2014, 2015, 2016, and 2017, Mississippi Power submitted its annual PEP lookback filing for the prior year, which for 2013 and 2014 each indicated no surcharge or refund and for each of 2015 and 2016 indicated a $5 million surcharge. Additionally, in July 2016, in November 2016, and on November 15, 2017, Mississippi Power submitted its annual projected PEP filings for 2016, 2017, and 2018, respectively, which for 2016 and 2017 indicated no change in rates and for 2018 indicated a rate increase of 4%, or $38 million in annual revenues. The Mississippi PSC suspended each of these filings to allow more time for review.

On February 7, 2018, Mississippi Power submitted its revised 2018 projected PEP filing to the Mississippi PSC, which reflected the impacts of the Tax Reform Legislation, requesting an increase in annual retail revenues of $26 million based on a performance adjusted ROE of 9.33% and an increased equity ratio of 55%.

On March 22, 2018, Mississippi Power submitted its annual PEP lookback filing for 2017, which reflected no surcharge or refund.

On July 27, 2018, Mississippi Power and the Mississippi Public Utilities Staff (MPUS) entered into a settlement agreement with respect to the 2018 PEP filing and all unresolved PEP filings for prior years (PEP Settlement Agreement), which was approved by the Mississippi PSC on August 7, 2018. Rates under the PEP Settlement Agreement will take effect for the first billing cycle of September 2018.

The PEP Settlement Agreement provides for an increase of approximately $21.6 million in annual base retail revenues, which excludes approximately $5.5 million requested for certain compensation costs contested by the MPUS. Under the PEP Settlement Agreement, Mississippi Power expects to defer these costs for 2018 and 2019 as a regulatory asset. The Mississippi PSC is currently expected to rule on the appropriate treatment for such costs in connection with Mississippi Power's next base rate case, which is scheduled to be filed in the fourth quarter 2019 (2019 Base Rate Case). The ultimate outcome of this matter cannot be determined at this time.

Pursuant to the PEP Settlement Agreement, Mississippi Power's performance-adjusted allowed ROE will be 9.31% and its allowed equity ratio will remain at 50%, pending further review by the Mississippi PSC. In lieu of the requested equity ratio increase, Mississippi Power will retain $44 million of excess accumulated deferred income taxes resulting from the Tax Reform Legislation, which had been proposed to be amortized beginning in 2018, until the conclusion of the 2019 Base Rate Case. Further, Mississippi Power will seek equity contributions sufficient to restore its equity ratio (which was 43.5% at June 30, 2018) to the 50% target. In the event Mississippi Power's actual average equity ratio for 2018 is more than 1% higher or lower than the 50% target, Mississippi Power will defer the corresponding difference in its revenue requirement as a regulatory asset or liability for resolution in the 2019 Base Rate Case.

Pursuant to the PEP Settlement Agreement, PEP proceedings will be suspended until after the conclusion of the 2019 Base Rate Case and Mississippi Power will not be required to make any PEP filings for regulatory years 2018, 2019, and 2020. The PEP Settlement Agreement also resolves all open PEP filings with no change to customer rates. As a result, in the third quarter 2018, Mississippi Power expects to recognize revenues of $5 million previously reserved in connection with the 2012 PEP lookback filing.

Energy Efficiency

On May 8, 2018, the Mississippi PSC issued an order approving Mississippi Power's revised annual projected Energy Efficiency Cost Rider 2018 compliance filing, submitted on May 3, 2018, which increased annual retail revenues by approximately $3 million effective with the first billing cycle for June 2018.

Environmental Compliance Overview Plan

On August 3, 2018, Mississippi Power and the MPUS entered into a settlement agreement with respect to the 2018 ECO Plan filing (ECO Settlement Agreement), which provides for an increase of approximately $17 million in annual base retail revenues and was approved by the Mississippi PSC on August 7, 2018. Rates under the ECO Settlement Agreement will take effect for the first billing cycle of September 2018 and will continue in effect until modified by the Mississippi PSC. These revenues are expected to be sufficient to recover the costs included in Mississippi Power's request for 2018, as well as the remaining deferred amounts that were originally expected to be recovered in 2019. In accordance with the ECO Settlement Agreement, ECO Plan proceedings will be suspended until after the conclusion of the 2019 Base Rate Case and Mississippi Power will not be required to make any ECO Plan filings for 2018, 2019, and 2020, with any necessary true-ups to be reflected in the 2019 Base Rate Case. The ECO Settlement Agreement contains the same terms as the PEP Settlement Agreement described herein with respect to allowed ROE and equity ratio.

Ad Valorem Tax Adjustment

On May 8, 2018, the Mississippi PSC approved Mississippi Power's annual ad valorem tax adjustment factor filing for 2018, which included an annual rate increase of 0.8%, or $7 million, in annual retail revenues effective with the first billing cycle for June 2018, primarily due to increased assessments.

Southern Company Gas

See Note 3 to the financial statements of Southern Company and Southern Company Gas under "Regulatory Matters – Southern Company Gas" and "Regulatory Matters," respectively, in Item 8 of the Form 10-K for additional information regarding Southern Company Gas' regulatory matters.

Riders

On April 19, 2018, the Illinois Commission approved Nicor Gas' variable income tax adjustment rider. This rider provides for refund or recovery of changes in income tax expense that result from income tax rates that differ from those used in Nicor Gas' last rate case. Customer refunds began on July 1, 2018 related to the January 1, 2018 through May 4, 2018 impacts of the Tax Reform Legislation. The impact of the Tax Reform Legislation subsequent to May 4, 2018 was addressed in Nicor Gas' approved rehearing request discussed herein under "Settled Base Rate Cases."

Natural Gas Cost Recovery

Southern Company Gas has established natural gas cost recovery rates approved by the relevant state regulatory agencies in the states in which it serves. Natural gas cost recovery revenues are adjusted for differences in actual recoverable natural gas costs and amounts billed in current regulated rates. Changes in the billing factor will not have a significant effect on Southern Company's or Southern Company Gas' revenues or net income, but will affect cash flows.

Base Rate Cases

Settled Base Rate Cases

In October 2017, Florida City Gas filed a general base rate case with the Florida PSC requesting an annual revenue increase of$19 million, which included an interim rate increase of $5 million annually that was approved and became effective January 12, 2018, subject to refund. On March 26, 2018, the Florida PSC approved a settlement that, after including the impact of the Tax Reform Legislation, provides for an $11.5 million increase in annual base rate revenues, effective June 1, 2018, based on a ROE of 10.19%.

On February 23, 2018, Atlanta Gas Light revised its annual base rate filing to reflect the impacts of the Tax Reform Legislation and requested a $16 million rate reduction in 2018. On May 15, 2018, the Georgia PSC approved a stipulation for Atlanta Gas Light's annual base rates to remain at the 2017 level for 2018 and 2019, with customer credits of $8 million in each of July 2018 and October 2018 to reflect the impacts of the Tax Reform Legislation. The Georgia PSC maintained Atlanta Gas Light's previously authorized earnings band based on a ROE between 10.55% and 10.95% and increased the allowed equity ratio by 4% to an equity ratio of 55% to address the negative cash flow and credit metric impacts of the Tax Reform Legislation. Additionally, Atlanta Gas Light is required to file a traditional base rate case on or before June 1, 2019 for rates effective January 1, 2020.

On May 2, 2018, the Illinois Commission approved Nicor Gas' rehearing request for revised base rates to incorporate the reduction in the federal income tax rate as a result of the Tax Reform Legislation. The resulting decrease of approximately$44 million in annual base rate revenues became effective May 5, 2018. Nicor Gas' previously-authorized capital structure and ROE of9.8% were not addressed in the rehearing and remain unchanged. The impact of the Tax Reform Legislation prior to May 5, 2018 was addressed in the variable income tax rider discussed herein under "Riders."

Pending Base Rate Case

On February 15, 2018, Chattanooga Gas filed a general base rate case with the Tennessee Public Utility Commission (PUC) requesting a $7 million increase in annual base rate revenues. The requested increase, which, in accordance with a Tennessee PUC order, incorporated the effects of the Tax Reform Legislation, was based on a projected test year ending June 30, 2019 and a ROE of 11.25%. The Tennessee PUC is expected to rule on the requested increase in the third quarter 2018.

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

Other

The New Jersey BPU, Maryland PSC, and Virginia Commission each issued an order effective January 1, 2018 that requires utilities in their respective states to defer as a regulatory liability the impact of the Tax Reform Legislation, including the reduction in the corporate income tax rate to 21% and the impact of the flowback of excess deferred income taxes. On June 22, 2018, the New Jersey BPU approved a $12 million reduction in Elizabethtown Gas' annual base rate revenues. On March 28, 2018, the Maryland PSC approved a $0.1 million reduction in Elkton Gas' annual base rate revenues effective April 1, 2018. Credits were issued to customers in Maryland in May 2018 and will be issued to customers in New Jersey in the third quarter 2018 for the impact of the Tax Reform Legislation on the January 2018 through March 2018 billing periods.

On April 25, 2018, the Virginia Commission issued an order indicating that any proposal beyond a proposed base rate reduction to reflect the cost savings from the Tax Reform Legislation must be made through a general base rate case. Virginia Natural Gas expects to address the cost savings from the Tax Reform Legislation in the third quarter 2018 by filing an annual information form. The Virginia Commission is expected to rule on the impact of the Tax Reform Legislation by the first half of 2019. The ultimate outcome of this matter cannot be determined at this time.

Regulatory Infrastructure Programs

Southern Company Gas is engaged in various infrastructure programs that update or expand its gas distribution systems to improve reliability and help ensure the safety of its utility infrastructure, and recovers in rates its investment and a return associated with these infrastructure programs. See Note 3 to the financial statements of Southern Company and Southern Company Gas under "Regulatory Matters – Southern Company Gas – Regulatory Infrastructure Programs" and "Regulatory Matters – Regulatory Infrastructure Programs," respectively, in Item 8 of the Form 10-K for additional information.

Atlanta Gas Light's Pipeline Replacement Program

One of the capital projects under Atlanta Gas Light's Pipeline Replacement Program experienced construction issues and Atlanta Gas Light was required to complete mitigation work prior to placing it in service. In the first quarter 2018, Atlanta Gas Light recovered $7 million from the final settlement of contractor litigation claims. Mitigation costs recovered through the legal process are retained by Atlanta Gas Light. For additional information on the Pipeline Replacement Program settlement, see Note 3 to the financial statements of Southern Company Gas under "Regulatory Matters – PRP Settlement" in Item 8 of the Form 10-K.

Nuclear Construction

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

In 2009, the Georgia PSC certified construction of Plant Vogtle Units 3 and 4. In 2012, the NRC issued the related combined construction and operating licenses, which allowed full construction of the two AP1000 nuclear units (with electric generating capacity of approximately 1,100 MWs each) and related facilities to begin. Until March 2017, construction on Plant Vogtle Units 3 and 4 continued under the Vogtle 3 and 4 Agreement, which was a substantially fixed price agreement. In March 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code.

In connection with the EPC Contractor's bankruptcy filing, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into the Interim Assessment Agreement with the EPC Contractor to allow construction to continue. The Interim Assessment Agreement expired in July 2017 when Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the EPC Contractor entered into the Vogtle Services Agreement. Under the Vogtle Services Agreement, Westinghouse provides facility design and engineering services, procurement and technical support, and staff augmentation on a time and materials cost basis. The Vogtle Services Agreement will continue until the start-up and testing of Plant Vogtle Units 3 and 4 are complete and electricity is generated and sold from both units. The Vogtle Services Agreement is terminable by the Vogtle Owners upon 30 days' written notice.

In October 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into a construction completion agreement with Bechtel, whereby Bechtel will serve as the primary contractor for the remaining construction activities for Plant Vogtle Units 3 and 4 (Bechtel Agreement). The Bechtel Agreement is a cost reimbursable plus fee arrangement, whereby Bechtel is reimbursed for actual costs plus a base fee and an at-risk fee, which is subject to adjustment based on Bechtel's performance against cost and schedule targets. Each Vogtle Owner is severally (not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to Bechtel under the Bechtel Agreement. The Vogtle Owners may terminate the Bechtel Agreement at any time for their convenience, provided that the Vogtle Owners will be required to pay amounts related to work performed prior to the termination (including the applicable portion of the base fee), certain termination-related costs, and, at certain stages of the work, the applicable portion of the at-risk fee. Bechtel may terminate the Bechtel Agreement under certain circumstances, including certain Vogtle Owner suspensions of work, certain breaches of the Bechtel Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events. Pursuant to the Loan Guarantee Agreement between Georgia Power and the DOE, Georgia Power is required to obtain the DOE's approval of the Bechtel Agreement prior to obtaining any further advances under the Loan Guarantee Agreement.

In December 2017, the Georgia PSC approved Georgia Power's seventeenth VCM report, which included a recommendation to continue construction of Plant Vogtle Units 3 and 4, with Southern Nuclear serving as project manager and Bechtel serving as the primary construction contractor.

Cost and Schedule

In preparation for its nineteenth VCM filing, Georgia Power requested Southern Nuclear to perform a full cost reforecast for the project. Georgia Power's approximate proportionate share of the remaining estimated capital cost to complete Plant Vogtle Units 3 and 4 by the expected in-service dates of November 2021 and November 2022, respectively, is as follows:

	(in billions)
Base project capital cost forecast(a)(b)	$	8.0
Construction contingency estimate	0.4
Total project capital cost forecast(a)(b)	8.4
Net investment as of June 30, 2018(b)	(4.0		)
Remaining estimate to complete(a)	$	4.4

(a) Excludes financing costs expected to be capitalized through AFUDC of approximately $350 million.

(b) Net of $1.7 billion received from Toshiba in 2017 under the Guarantee Settlement Agreement and $188 million in Customer Refunds recognized as a regulatory liability in 2017.

Georgia Power estimates that its financing costs for construction of Plant Vogtle Units 3 and 4 will total approximately $3.2 billion, of which $1.7 billion had been incurred through June 30, 2018.

The $0.7 billion increase to the base capital cost forecast reflected in the table above primarily results from changed assumptions related to the finalization of contract scopes and management responsibilities for Bechtel and over 60 subcontractors, labor productivity rates, and craft labor incentives, as well as the related levels of project management, oversight, and support, including field supervision and engineering support.

Although Georgia Power believes these incremental costs are reasonable and necessary to complete the project and the Georgia PSC's order in the seventeenth VCM proceeding specifically states that the construction of Plant Vogtle Units 3 and 4 is not subject to a cost cap, Georgia Power does not intend to seek rate recovery for these cost increases included in the current base capital cost forecast (or any related financing costs), which will be filed with the Georgia PSC in the nineteenth VCM report at the end of August 2018. In connection with future VCM filings, Georgia Power may request the Georgia PSC to evaluate costs currently included in the construction contingency estimate for rate recovery as and when they are appropriately included in the base capital cost forecast. After considering the significant level of uncertainty that exists regarding the future recoverability of costs included in the construction contingency estimate since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in these future regulatory proceedings, Georgia Power has recorded a total pre-tax charge to income of $1.1 billion ($0.8 billion after tax), which includes the total increase in the capital cost forecast and construction contingency estimate as of June 30, 2018.

Subsequent to the EPC Contractor bankruptcy filing, a number of subcontractors to the EPC Contractor alleged non-payment by the EPC Contractor for amounts owed for work performed on Plant Vogtle Units 3 and 4. Georgia Power, acting for itself and as agent for the Vogtle Owners, has taken actions to remove liens filed by these subcontractors through the posting of surety bonds. Related to such liens, certain subcontractors have filed, and additional subcontractors may file, lawsuits against the EPC Contractor and the Vogtle Owners to preserve their payment rights with respect to such claims. All known amounts associated with the removal of subcontractor liens and other EPC Contractor pre-petition accounts payable have been paid or accrued as of June 30, 2018. The ultimate liability is expected to be finalized in connection with the completion of the sale of Westinghouse.

As construction continues, challenges with management of contractors, subcontractors, and vendors; labor productivity, availability, and/or cost escalation; procurement, fabrication, delivery, assembly, and/or installation, including any required engineering changes, of plant systems, structures, and components (some of which are based on new technology that is just beginning initial operation in the global nuclear industry at this scale); or other issues could arise and change the projected schedule and estimated cost.

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. 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, 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.

The ultimate outcome of these matters cannot be determined at this time. However, any extension of the project schedule is currently estimated to result in additional base capital costs of approximately $50 million per month, based on Georgia Power's ownership interests, and AFUDC of approximately $12 million per month. While Georgia Power is not precluded from seeking recovery of any future capital cost forecast increase, management will ultimately determine whether or not to seek recovery. Any further changes to the capital cost forecast that are not expected to be recoverable through regulated rates will be required to be charged to income and such charges could be material.

Joint Owner Contracts

In November 2017, the Vogtle Owners entered into an amendment to their joint ownership agreements for Plant Vogtle Units 3 and 4 (as amended, Vogtle Joint Ownership Agreements) to provide for, among other conditions, additional Vogtle Owner approval requirements. Pursuant to the Vogtle Joint Ownership Agreements, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction if certain adverse events occur, including: (i) the bankruptcy of Toshiba; (ii) termination or rejection in bankruptcy of certain agreements, including the Vogtle Services Agreement or the Bechtel Agreement; (iii) the Georgia PSC or Georgia Power determines that any of Georgia Power's costs relating to the construction of Plant Vogtle Units 3 and 4 will not be recovered in retail rates because such costs are deemed unreasonable or imprudent; or (iv) an increase in the construction budget contained in the seventeenth VCM report of more than $1 billion or extension of the project schedule contained in the seventeenth VCM report of more than one year. In addition, pursuant to the Vogtle Joint Ownership Agreements, the required approval of holders of ownership interests in Plant Vogtle Units 3 and 4 is at least (i) 90% for a change of the primary construction contractor and (ii) 67% for material amendments to the Vogtle Services Agreement or agreements with Southern Nuclear or the primary construction contractor, including the Bechtel Agreement. The Vogtle Joint Ownership Agreements also confirm that the Vogtle Owners' sole recourse against Georgia Power or Southern Nuclear for any action or inaction in connection with their performance as agent for the Vogtle Owners is limited to removal of Georgia Power and/or Southern Nuclear as agent, except in cases of willful misconduct.

As a result of the increase in the total project capital cost forecast and Georgia Power's decision not to seek rate recovery of the increase in the base capital costs as described in "Cost and Schedule" herein, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction. The Vogtle Owners are expected to conduct these votes in the third quarter 2018.

If the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 do not vote to continue construction, the Vogtle Joint Ownership Agreements provide that the project will be cancelled, and construction will cease. In the event that fewer than 90% of the Vogtle Owners vote to continue construction, Georgia Power and the other Vogtle Owners will assess options for Plant Vogtle Units 3 and 4. If Plant Vogtle Units 3 and 4 were cancelled and Georgia Power was unable to recover costs it has incurred in connection with the project, Southern Company's and Georgia Power's results of operations, cash flow, and financial condition would be materially impacted. The ultimate outcome of this matter cannot be determined at this time.

Regulatory Matters

In 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4 with a certified capital cost of $4.418 billion. In addition, in 2009 the Georgia PSC approved inclusion of the Plant Vogtle Units 3 and 4 related CWIP accounts in rate base, and the State of Georgia enacted the Georgia Nuclear Energy Financing Act, which allows Georgia Power to recover financing costs for Plant Vogtle Units 3 and 4. Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff up to the certified capital cost of $4.418 billion. As of June 30, 2018, Georgia Power had recovered approximately $1.7 billion of financing costs. Financing costs related to capital costs above $4.418 billion will be recovered through AFUDC; however, Georgia Power will not record AFUDC related to any capital costs in excess of the total deemed reasonable by the Georgia PSC (currently $7.3 billion) and not requested for rate recovery.

Georgia Power is required to file semi-annual VCM reports with the Georgia PSC by February 28 and August 31 of each year. In 2013, in connection with the eighth VCM report, the Georgia PSC approved a stipulation between Georgia Power and the staff of the Georgia PSC to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate in accordance with the 2009 certification order until the completion of Plant Vogtle Unit 3, or earlier if deemed appropriate by the Georgia PSC and Georgia Power.

In 2016, the Georgia PSC voted to approve a settlement agreement (Vogtle Cost Settlement Agreement) resolving certain prudency matters in connection with the fifteenth VCM report. In December 2017, the Georgia PSC voted to approve (and issued its related order on January 11, 2018) certain recommendations made by Georgia Power in the seventeenth VCM report and modifying the Vogtle Cost Settlement Agreement. The Vogtle Cost Settlement Agreement, as modified by the January 11, 2018 order, resolved the following regulatory matters related to Plant Vogtle Units 3 and 4: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report should be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement was reasonable and prudent and none of the amounts paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) (a) capital costs incurred up to $5.68 billion would be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, (b) Georgia Power would have the burden to show that any capital costs above $5.68 billion were prudent, and (c) a revised capital cost forecast of $7.3 billion (after reflecting the impact of payments received under the Guarantee Settlement Agreement and Customer Refunds) was found reasonable; (iv) construction of Plant Vogtle Units 3 and 4 should be completed, with Southern Nuclear serving as project manager and Bechtel as primary contractor; (v) approved and deemed reasonable Georgia Power's revised schedule placing Plant Vogtle Units 3 and 4 in service in November 2021 and November 2022, respectively; (vi) confirmed that the revised cost forecast does not represent a cost cap and that prudence decisions on cost recovery will be made at a later date, consistent with applicable Georgia law; (vii) reduced the ROE used to calculate the NCCR tariff (a) from 10.95% (the ROE rate setting point authorized by the Georgia PSC in the 2013 ARP) to 10.00% effective January 1, 2016, (b) from 10.00% to 8.30%, effective January 1, 2020, and (c) from 8.30% to 5.30%, effective January 1, 2021 (provided that the ROE in no case will be less than Georgia Power's average cost of long-term debt); (viii) reduced the ROE used for AFUDC equity for Plant Vogtle Units 3 and 4 from 10.00% to Georgia Power's average cost of long-term debt, effective January 1, 2018; and (ix) agreed that upon Unit 3 reaching commercial operation, retail base rates would be adjusted to include carrying costs on those capital costs deemed prudent in the Vogtle Cost Settlement Agreement. The January 11, 2018 order also stated that if Plant Vogtle Units 3 and 4 are not commercially operational by June 1, 2021 and June 1, 2022, respectively, the ROE used to calculate the NCCR tariff will be further reduced by 10 basis points each month (but not lower than Georgia Power's average cost of long-term debt) until the respective unit is commercially operational. The ROE reductions negatively impacted earnings by approximately $25 million in 2017 and are estimated to have negative earnings impacts of approximately $100 million in 2018 and an aggregate of $585 million from 2019 to 2022.

In its January 11, 2018 order, the Georgia PSC also stated if other conditions change and assumptions upon which Georgia Power's seventeenth VCM report are based do not materialize, the Georgia PSC reserved the right to reconsider the decision to continue construction.

On February 12, 2018, Georgia Interfaith Power & Light, Inc. and Partnership for Southern Equity, Inc. filed a petition appealing the Georgia PSC's January 11, 2018 order with the Fulton County Superior Court. On March 8, 2018, Georgia Watch filed a similar appeal to the Fulton County Superior Court for judicial review of the Georgia PSC's final decision and denial of Georgia Watch's motion for reconsideration. Georgia Power believes the two appeals have no merit; however, an adverse outcome in either appeal could have a material impact on Southern Company's and Georgia Power's results of operations, financial condition, and liquidity.

The Georgia PSC has approved seventeen VCM reports covering the periods through June 30, 2017, including total construction capital costs incurred through that date of $4.4 billion. On August 21, 2018, the Georgia PSC is scheduled to vote on Georgia Power's eighteenth VCM report, which requested approval of $448 million of construction capital costs (excluding the $1.7 billion received from Toshiba under the Guarantee Settlement Agreement and the $188 million in Customer Refunds recognized as a regulatory liability) incurred from July 1, 2017 through December 31, 2017.

On August 31, 2018, Georgia Power will file its nineteenth VCM report with the Georgia PSC, which will reflect the revised capital cost forecast discussed previously and request approval of $578 million of construction capital costs incurred from January 1, 2018 through June 30, 2018.

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

DOE Financing

As of June 30, 2018, Georgia Power had borrowed $2.6 billion related to Plant Vogtle Units 3 and 4 costs through the Loan Guarantee Agreement and a multi-advance credit facility among Georgia Power, the DOE, and the FFB, which provides for borrowings of up to $3.46 billion, subject to the satisfaction of certain conditions. In September 2017, the DOE issued a conditional commitment to Georgia Power for up to approximately $1.67 billion in additional guaranteed loans under the Loan Guarantee Agreement. In June 2018, the DOE approved a request by Georgia Power to extend the conditional commitment to September 30, 2018. Any further extension must be approved by the DOE. Final approval and issuance of these additional loan guarantees by the DOE cannot be assured and are subject to the negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions, including the Vogtle Owners' votes to continue construction. See Note 6 to the financial statements of Southern Company and Georgia Power under "DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K and Note (F) under "DOE Loan Guarantee Borrowings" for additional information, including applicable covenants, events of default, mandatory prepayment events (including any decision not to continue construction of Plant Vogtle Units 3 and 4), and conditions to borrowing.

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

Kemper County Energy Facility

For additional information on the Kemper County energy facility, see Note 3 to the financial statements of Southern Company and Mississippi Power under "Kemper County Energy Facility" in Item 8 of the Form 10-K.

As the mining permit holder for the Kemper County energy facility, Liberty Fuels Company, LLC has a legal obligation to perform mine reclamation, and Mississippi Power has a contractual obligation to fund all reclamation activities. Mine reclamation began in the first quarter 2018. See Note 1 to the financial statements of Southern Company and Mississippi Power under "Asset Retirement Obligations and Other Costs of Removal" and of Mississippi Power under "Variable Interest Entities" in Item 8 of the Form 10-K for additional information.

As of June 30, 2018, Mississippi Power recorded charges to income of an immaterial amount for the second quarter 2018 and $45 million ($33 million after tax) for year-to-date 2018, primarily resulting from the abandonment and related closure activities for the mine and gasifier-related assets at the Kemper County energy facility. Additional closure costs for the mine and gasifier-related assets, currently estimated to cost up to $25 million pre-tax (excluding salvage, net of dismantlement costs), are expected to be incurred during the remainder of 2018 and 2019. In addition, period costs, including, but not limited to, costs for compliance and safety, ARO accretion, and property taxes for the mine and gasifier-related assets, are estimated at $4 million for the remainder of 2018, $7 million in 2019, and $4 million annually beginning in 2020. The ultimate outcome of this matter cannot be determined at this time.

Reserve Margin Plan

On August 6, 2018, Mississippi Power filed its proposed RMP, as required by the Mississippi PSC's order in the docket established for the purposes of pursuing a global settlement of the costs related to the Kemper County energy facility. Under the RMP, Mississippi Power proposes alternatives that would reduce its reserve margin, with the most economic of the alternatives being the2-year and 7-year acceleration of the retirement of Plant Watson Units 4 and 5, respectively, to the first quarter 2022 and the 4-year acceleration of the retirement of Plant Greene County Units 1 and 2 to the third quarter 2021 and the third quarter 2022, respectively, in order to lower or avoid operating costs. The Plant Greene County unit retirements would require the completion by Alabama Power of proposed transmission and system reliability improvements, as well as agreement by Alabama Power. The RMP filing also states that, in the event the Mississippi PSC ultimately approves an alternative that includes an accelerated retirement, Mississippi Power would require authorization to defer in a regulatory asset for future recovery the remaining net book value of the units at the time of retirement. Mississippi Power expects the MPUS and other interested parties to review the proposal prior to resolution by the Mississippi PSC. The ultimate outcome of this matter cannot be determined at this time. However, if approved by the Mississippi PSC, the alternatives are not expected to have any adverse impact on customer rates.

Other Matters

Investments in Leveraged Leases

See Note 1 to the financial statements of Southern Company under "Leveraged Leases" in Item 8 of the Form 10-K for additional information regarding a Southern Company Holdings Inc. (Southern Holdings) subsidiary's leveraged lease agreements and concerns about the financial and operational performance of one of the lessees and the associated generation assets.

The ability of the lessees to make required payments to the Southern Holdings subsidiary is dependent on the operational performance of the assets. As a result of operational improvements in the first half of 2018, the June 2018 lease payment was paid in full and the December 2018 lease payment is currently expected to be paid in full. However, operational issues and the resulting cash liquidity challenges persist and significant concerns continue regarding the lessee's ability to make the remaining semi-annual lease payments. These operational challenges may also impact the expected residual value of the assets at the end of the lease term in 2047. If any future lease payment is not paid in full, the Southern Holdings subsidiary may be unable to make its corresponding payment to the holders of the underlying non-recourse debt related to the generation assets. Failure to make the required payment to the debtholders would represent an event of default that would give the debtholders the right to foreclose on, and take ownership of, the generation assets from the Southern Holdings subsidiary, in effect terminating the lease and resulting in the write-off of the related lease receivable, which would result in a reduction in net income of approximately $86 million after tax based on the lease receivable balance as of June 30, 2018. Southern Company has evaluated the recoverability of the lease receivable and the expected residual value of the generation assets at the end of the lease under various scenarios and has concluded that its investment in the leveraged lease is not impaired as of June 30, 2018. Southern Company will continue to monitor the operational performance of the underlying assets and evaluate the ability of the lessee to continue to make the required lease payments. The ultimate outcome of this matter cannot be determined at this time.

Natural Gas Storage

A wholly-owned subsidiary of Southern Company Gas owns and operates a natural gas storage facility consisting of two salt dome caverns in Louisiana. Periodic integrity tests are required in accordance with rules of the Louisiana Department of Natural Resources (DNR). In August 2017, in connection with an ongoing integrity project, updated seismic mapping indicated the proximity of one of the caverns to the edge of the salt dome may be less than the required minimum and could result in Southern Company Gas retiring the cavern early. At June 30, 2018, the facility's property, plant, and equipment had a net book value of $111 million, of which the cavern itself represents approximately 20%. A potential early retirement of this cavern is dependent upon several factors including compliance with an order from the Louisiana DNR detailing the requirements to place the cavern back in service, which includes, among other things, obtaining core samples to determine the composition of the sheath surrounding the edge of the salt dome.

The cavern continues to maintain its pressures and overall structural integrity. Southern Company Gas intends to monitor the cavern and comply with the Louisiana DNR order through 2020 and place the cavern back in service in 2021. These events were considered in connection with Southern Company Gas' 2017 long-lived asset impairment analysis, which determined there was no impairment. Any future changes in results of monitoring activities, rates at which expiring capacity contracts are re-contracted, timing of placing the cavern back in service, or Louisiana DNR requirements could trigger impairment. Further, early retirement of the cavern could trigger impairment of other long-lived assets associated with the natural gas storage facility. The ultimate outcome of this matter cannot be determined at this time, but could have a significant impact on Southern Company's financial statements and a material impact on Southern Company Gas' financial statements.

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Revenue from Contracts with Customers

6 Months Ended

Jun. 30, 2018

Revenue from Contract with Customer [Abstract]

Revenue from Contracts with Customers

REVENUE FROM CONTRACTS WITH CUSTOMERS

The registrants generate revenues from a variety of sources, some of which are excluded from the scope of ASC 606, such as leases, derivatives, and certain cost recovery mechanisms. See Note (A) under "Recently Adopted Accounting Standards – Revenue" for additional information on the adoption of ASC 606 for revenue from contracts with customers.

The majority of the revenues of the traditional electric operating companies and Southern Company Gas are generated from contracts with retail electric and natural gas distribution customers. Revenues from this integrated service to deliver electricity or gas when and if called upon by the customer is recognized as a single performance obligation satisfied over time and is recognized at a tariff rate as electricity or gas is delivered to the customer during the month. The traditional electric operating companies and Southern Company Gas exclude taxes imposed on the customer and collected on behalf of governmental agencies to be remitted to these agencies from the transaction price in determining the revenue related to contracts with a customer.

The traditional electric operating companies and Southern Power also have contracts with multiple performance obligations, such as capacity and energy in a wholesale PPA, where the contract's total transaction price is allocated to each performance obligation based on the standalone selling price. The standalone selling price is primarily determined by the price charged to customers for the specific goods or services transferred with the performance obligations. Generally, the registrants recognize revenue as the performance obligations are satisfied over time as electricity or natural gas is delivered to the customer or as generation capacity is available to the customer. At Southern Company Gas, the performance obligations related to wholesale gas services are satisfied, and revenue is recognized, at a point in time when natural gas is delivered to the customer.

The registrants generally have a right to consideration in an amount that corresponds directly with the value to the customer of the entity's performance completed to date and may recognize revenue in the amount to which the entity has a right to invoice and has elected to recognize revenue for its sales of electricity, capacity, and natural gas using the invoice practical expedient. In addition, payment for goods and services rendered is typically due in the subsequent month following satisfaction of the registrants' performance obligation.

The following tables disaggregate revenue sources for the three and six months ended June 30, 2018:

	For the Three Months Ended June 30, 2018			For the Six Months Ended June 30, 2018
	(in millions)
Southern Company
Operating revenues
Retail electric revenues(a)
Residential	$	1,579		$	3,118
Commercial	1,315			2,557
Industrial	814			1,569
Other	32			64
Natural gas distribution revenues	642			1,865
Alternative revenue programs(b)	(4		)	(27		)
Total retail electric and gas distribution revenues	$	4,378		$	9,146
Wholesale energy revenues(c)(d)	459			928
Wholesale capacity revenues(d)	152			302
Other natural gas revenues(e)	68			476
Other revenues(f)	570			1,147
Total operating revenues	$	5,627		$	11,999

(a) Retail electric revenues include $18 million and $36 million of leases for the three and six months ended June 30, 2018, respectively, and a net increase of $68 million and $101 million for the three and six months ended June 30, 2018, respectively, from certain cost recovery mechanisms that are not accounted for as revenue under ASC 606. See Note 3 to the financial statements of Southern Company under "Regulatory Matters" in Item 8 of the Form 10-K for additional information on cost recovery mechanisms.

(b) See Note 1 to the financial statements of Southern Company under "Revenues" in Item 8 of the Form 10-K for additional information on alternative revenue programs at the natural gas distribution utilities. Alternative revenue program revenues are presented net of any previously recognized program amounts billed to customers during the same accounting period.

(c) Wholesale energy revenues include $61 million and $155 million for the three and six months ended June 30, 2018, respectively, of revenues accounted for as derivatives, primarily related to physical energy sales in the wholesale electricity market. See Note (I) for additional information on energy-related derivative contracts.

(d) Wholesale energy and wholesale capacity revenues include $118 million and $31 million, respectively, for the three months ended June 30, 2018 and $187 million and $61 million, respectively, for the six months ended June 30, 2018 of PPA contracts accounted for as leases.

(e) Other natural gas revenues related to Southern Company Gas' energy and risk management activities are presented net of the related costs of those activities and include gross third-party revenues of $1.3 billion and $3.3 billion for the three and six months ended June 30, 2018, respectively, of which $0.7 billion and $1.8 billion, respectively, relates to contracts that are accounted for as derivatives. See Note (L) under "Southern Company Gas" for additional information on the components of wholesale gas services operating revenues.

(f) Other revenues include $89 million and $183 million for the three and six months ended June 30, 2018, respectively, of revenues not accounted for under ASC 606.

	Alabama Power		Georgia Power		Gulf Power		Mississippi Power
	(in millions)
For the Three Months Ended June 30, 2018
Operating revenues
Retail revenues(a)(b)
Residential	$	557	$	785	$	172	$	65
Commercial	402		749		96		68
Industrial	372		335		31		76
Other	7		20		2		3
Total retail electric revenues	$	1,338	$	1,889	$	301	$	212
Wholesale energy revenues(c)	71		26		21		73
Wholesale capacity revenues	25		13		6		1
Other revenues(b)(d)	69		120		16		11
Total operating revenues	$	1,503	$	2,048	$	344	$	297
For the Six Months Ended June 30, 2018
Operating revenues
Retail revenues(a)(b)
Residential	$	1,127	$	1,529	$	337	$	125
Commercial	774		1,466		188		130
Industrial	710		650		63		146
Other	13		43		3		5
Total retail electric revenues	$	2,624	$	3,688	$	591	$	406
Wholesale energy revenues(c)	172		66		56		167
Wholesale capacity revenues	49		27		12		5
Other revenues(b)(d)	131		227		33		20
Total operating revenues	$	2,976	$	4,008	$	692	$	598

(a) Retail revenues at Alabama Power, Georgia Power, Gulf Power, and Mississippi Power include a net increase or (net reduction) of $78 million, $3 million, $(12) million, and $(1) million, respectively, for the three months ended June 30, 2018 and $125 million, $12 million, $(28) million, and $(8) million, respectively, for the six months ended June 30, 2018 related to certain cost recovery mechanisms that are not accounted for as revenue under ASC 606. See Note 3 to the financial statements of Alabama Power, Georgia Power, Gulf Power, and Mississippi Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information on cost recovery mechanisms.

(b) Retail revenues and other revenues at Georgia Power include $18 million and $33 million, respectively, for the three months ended June 30, 2018 and $36 million and $66 million, respectively, for the six months ended June 30, 2018 of revenues accounted for as leases.

(c) Wholesale energy revenues at Alabama Power and Georgia Power include $4 million and $5 million, respectively, for the three months ended June 30, 2018 and $9 million and $13 million, respectively, for the six months ended June 30, 2018 accounted for as derivatives primarily related to physical energy sales in the wholesale electricity market. See Note (I) for additional information on energy-related derivative contracts.

(d) Other revenues at Alabama Power, Georgia Power, and Gulf Power include $26 million, $26 million, and $2 million, respectively, for the three months ended June 30, 2018 and $52 million, $53 million, and $4 million, respectively, for the six months ended June 30, 2018 of revenues not accounted for under ASC 606.

	For the Three Months Ended June 30, 2018		For the Six Months Ended June 30, 2018
	(in millions)
Southern Power
PPA capacity revenues(a)	$	144	$	282
PPA energy revenues(a)	302		556
Non-PPA revenues(b)	106		221
Other revenues	3		5
Total operating revenues	$	555	$	1,064

(a) PPA capacity revenues and PPA energy revenues include $47 million and $127 million, respectively, for the three months ended June 30, 2018 and $94 million and $203 million, respectively, for the six months ended June 30, 2018 related to PPAs accounted for as leases. See Note 1 to the financial statements of Southern Power under "Revenues" in Item 8 of the Form 10-K for additional information on capacity revenues accounted for as leases.

(b) Non-PPA revenues include $50 million and $129 million for the three and six months ended June 30, 2018, respectively, of revenues from short-term sales related to physical energy sales from uncovered capacity in the wholesale electricity market. See Note 1 to the financial statements of Southern Power under "Revenues" in Item 8 of the Form 10-K and Note (I) for additional information on energy-related derivative contracts.

	For the Three Months Ended June 30, 2018			For the Six Months Ended June 30, 2018
	(in millions)
Southern Company Gas
Operating revenues
Natural gas distribution revenues
Residential	$	273		$	933
Commercial	76			268
Transportation	7			24
Industrial	228			505
Other	58			135
Alternative revenue programs(a)	(4		)	(27		)
Total natural gas distribution revenues	$	638		$	1,838
Gas marketing services(b)	89			359
Wholesale gas services(c)	(15		)	131
Gas midstream operations	18			40
Other revenues	—			1
Total operating revenues	$	730		$	2,369

(a) See Note 1 to the financial statements of Southern Company Gas under "Revenues" in Item 8 of the Form 10-K for additional information on alternative revenue programs at the natural gas distribution utilities. Alternative revenue program revenues are presented net of any previously recognized program amounts billed to customers during the same accounting period.

(b) Gas marketing services includes $4 million for the six months ended June 30, 2018 of revenues not accounted for under ASC 606.

(c) Wholesale gas services revenues are presented net of the related costs associated with its energy trading and risk management activities. Operating revenues, as presented, include gross third-party revenues of $1.3 billion and $3.3 billion for the three and six months ended June 30, 2018, respectively, of which $0.7 billion and $1.8 billion, respectively, relates to contracts that are accounted for as derivatives. See Note (L) under "Southern Company Gas" for additional information on the components of wholesale gas services operating revenues and Note (I) for additional information on energy-related derivative contracts.

Contract Balances

The following table reflects the closing balances of receivables, contract assets, and contract liabilities related to revenues from contracts with customers as of June 30, 2018:

	Receivables		Contract Assets		Contract Liabilities
	(in millions)
Southern Company	$	2,785	$	33	$	36
Alabama Power	603		—		10
Georgia Power	840		9		9
Gulf Power	169		—		1
Mississippi Power	83		—		—
Southern Power	136		—		4
Southern Company Gas	570		—		1

As of June 30, 2018, Alabama Power had contract liabilities for outstanding performance obligations primarily related to extended service agreements. Georgia Power had contract assets primarily related to unregulated service agreements where payment is contingent on project completion. Georgia Power had contract liabilities for outstanding performance obligations primarily related to fixed retail customer bill programs where the payment is contingent upon Georgia Power's continued performance and the customer's continued participation in the program over the one-year contract term. Southern Company's unregulated distributed generation business had $23 million and $16 million of contract assets and contract liabilities, respectively, remaining for outstanding performance obligations.

Remaining Performance Obligations

The traditional electric operating companies and Southern Power have long-term contracts with customers in which revenues are recognized as performance obligations are satisfied over the contract term. These contracts primarily relate to PPAs whereby the traditional electric operating companies and Southern Power provide electricity and generation capacity to a customer. The revenue recognized for the delivery of electricity is variable; however, certain PPAs include a fixed payment for fixed generation capacity over the term of the contract. Southern Company's unregulated distributed generation business also has partially satisfied performance obligations related to certain fixed price contracts. Revenues from contracts with customers related to these performance obligations remaining at June 30, 2018 are expected to be recognized as follows:

	2018		2019		2020		2021		2022		2023 and Thereafter
	(in millions)
Southern Company(*)	$	263	$	352	$	322	$	322	$	310	$	1,960
Alabama Power	11		22		22		26		23		161
Georgia Power	20		41		38		40		30		113
Gulf Power	11		22		—		—		—		—
Mississippi Power	2		3		3		1		—		—
Southern Power(*)	211		310		283		277		276		1,809

(*) Excludes amounts related to held for sale assets. See Note (J) under "Southern Company's Sale of Gulf Power" and "Southern Power – Sale of Florida Plants" for additional information.

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Fair Value Measurements

6 Months Ended

Jun. 30, 2018

Fair Value Disclosures [Abstract]

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS

As of June 30, 2018, 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, 2018:	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(a)(b)	$	287	$	166	$	—	$	—	$	453
Foreign currency derivatives	—		132		—		—		132
Nuclear decommissioning trusts(c)	798		998		—		33		1,829
Cash equivalents	1,449		—		—		—		1,449
Other investments	9		—		1		—		10
Total	$	2,543	$	1,296	$	1	$	33	$	3,873
Liabilities:
Energy-related derivatives(a)(b)	$	422	$	151	$	—	$	—	$	573
Interest rate derivatives	—		68		—		—		68
Foreign currency derivatives	—		23		—		—		23
Contingent consideration	—		—		22		—		22
Total	$	422	$	242	$	22	$	—	$	686
Alabama Power
Assets:
Energy-related derivatives	$	—	$	8	$	—	$	—	$	8
Nuclear decommissioning trusts:(d)
Domestic equity	440		86		—		—		526
Foreign equity	61		55		—		—		116
U.S. Treasury and government agency securities	—		18		—		—		18
Corporate bonds	28		158		—		—		186
Mortgage and asset backed securities	—		18		—		—		18
Private equity	—		—		—		33		33
Other	7		—		—		—		7
Cash equivalents	495		—		—		—		495
Total	$	1,031	$	343	$	—	$	33	$	1,407
Liabilities:
Energy-related derivatives	$	—	$	9	$	—	$	—	$	9

	Fair Value Measurements Using:
As of June 30, 2018:	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	$	—	$	7	$	—	$	—	$	7
Nuclear decommissioning trusts:(d) (e)
Domestic equity	242		1		—		—		243
Foreign equity	—		135		—		—		135
U.S. Treasury and government agency securities	—		239		—		—		239
Municipal bonds	—		78		—		—		78
Corporate bonds	—		164		—		—		164
Mortgage and asset backed securities	—		41		—		—		41
Other	19		5		—		—		24
Total	$	261	$	670	$	—	$	—	$	931
Liabilities:
Energy-related derivatives	$	—	$	19	$	—	$	—	$	19
Interest rate derivatives	—		6		—		—		6
Total	$	—	$	25	$	—	$	—	$	25
Gulf Power
Assets:
Cash equivalents	$	27	$	—	$	—	$	—	$	27
Liabilities:
Energy-related derivatives	$	—	$	12	$	—	$	—	$	12
Mississippi Power
Assets:
Energy-related derivatives	$	—	$	3	$	—	$	—	$	3
Cash equivalents	205		—		—		—		205
Total	$	205	$	3	$	—	$	—	$	208
Liabilities:
Energy-related derivatives	$	—	$	9	$	—	$	—	$	9

	Fair Value Measurements Using:
As of June 30, 2018:	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	$	—	$	3	$	—	$	—	$	3
Foreign currency derivatives	—		132		—		—		132
Total	$	—	$	135	$	—	$	—	$	135
Liabilities:
Energy-related derivatives	$	—	$	3	$	—	$	—	$	3
Foreign currency derivatives	—		23		—		—		23
Contingent consideration	—		—		22		—		22
Total	$	—	$	26	$	22	$	—	$	48
Southern Company Gas
Assets:
Energy-related derivatives(a)(b)	$	287	$	144	$	—	$	—	$	431
Cash equivalents	1		—		—		—		1
Total	$	288	$	144	$	—	$	—	$	432
Liabilities:
Energy-related derivatives(a)(b)	$	422	$	99	$	—	$	—	$	521

(a) Excludes $3 million associated with premiums and certain weather derivatives accounted for based on intrinsic value rather than fair value.

(b) Excludes cash collateral of $183 million.

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

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

(e) Includes the investment securities pledged to creditors and collateral received and excludes payables related to the securities lending program. As of June 30, 2018, approximately $63 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 $14 million and $4 million, respectively, for the three and six months ended June 30, 2018 and increased by $55 million and $118 million, respectively, for the three and six months ended June 30, 2017. Alabama Power recorded an increase in fair value of $15 million and $10 million, respectively, for the three and six months ended June 30, 2018 and an increase of $28 million and $62 million, respectively, for the three and six months ended June 30, 2017 as a change in regulatory liabilities related to its AROs. Georgia Power recorded a decrease in fair value of $1 million and $6 million, respectively, for the three and six months ended June 30, 2018 and an increase of $27 million and $56 million, respectively, for the three and six months ended June 30, 2017 as a change in its regulatory asset related to its AROs.

Valuation Methodologies

The energy-related derivatives primarily consist of exchange-traded and 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 reflects 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 reflects 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 data and valuations of similar instruments. See Note (I) 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.

Southern Power has contingent payment obligations related to certain acquisitions whereby Southern Power is primarily obligated to make generation-based payments to the seller, which commenced at the commercial operation date of the respective facility and continue through 2026. The obligation is categorized as Level 3 under Fair Value Measurements as the fair value is determined using significant unobservable inputs for the forecasted facility generation in MW-hours, as well as other inputs such as a fixed dollar amount per MW-hour, and a discount rate. The fair value of contingent consideration reflects the net present value of expected payments and any periodic change arising from forecasted generation is expected to be immaterial.

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

As of June 30, 2018, the fair value measurements of private equity investments held in the nuclear decommissioning trusts 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, 2018:	Fair Value		Unfunded Commitments		Redemption Frequency	Redemption Notice Period
	(in millions)
Southern Company	$	33	$	33	Not Applicable	Not Applicable
Alabama Power	$	33	$	33	Not Applicable	Not Applicable

Private equity funds include a fund-of-funds that invests in high-quality private equity funds across several market sectors, funds that invest 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 10 years.

As of June 30, 2018, 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	$	45,806	$	46,481
Alabama Power	8,119		8,435
Georgia Power	10,294		10,499
Gulf Power	1,285		1,311
Mississippi Power	1,779		1,760
Southern Power	5,037		5,094
Southern Company Gas	5,823		5,957

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 Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Southern Power, and Southern Company Gas.

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Stockholders' Equity

6 Months Ended

Jun. 30, 2018

Equity [Abstract]

STOCKHOLDERS' EQUITY

STOCKHOLDERS' EQUITY

Earnings per Share

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

	Three Months Ended June 30, 2018	Three Months Ended June 30, 2017	Six Months Ended June 30, 2018	Six Months Ended June 30, 2017
	(in millions)
As reported shares	1,014	998	1,012	996
Effect of stock-based compensation	—	7	5	7
Diluted shares	1,014	1,005	1,017	1,003

Stock-based compensation awards that were not included in the diluted earnings per share calculation because they were anti-dilutive totaled approximately 5.3 million shares for the three months ended June 30, 2018 and were immaterial for the three months ended June 30, 2017 and six months ended June 30, 2018 and 2017.

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(a)
	(in thousands)			(in millions)
Balance at December 31, 2017	1,008,532	(929	)	$	24,167		$	—		$	1,361		$	25,528
Consolidated net income attributable to Southern Company	—	—		784			—			—			784
Other comprehensive income	—	—		41			—			—			41
Stock issued	6,590	—		222			—			—			222
Stock-based compensation	—	—		48			—			—			48
Cash dividends on common stock	—	—		(1,194		)	—			—			(1,194		)
Contributions from noncontrolling interests	—	—		—			—			31			31
Distributions to noncontrolling interests	—	—		—			—			(42		)	(42		)
Net income attributable to noncontrolling interests	—	—		—			—			17			17
Sale of SPSH noncontrolling interests(b)	—	—		(407		)	—			1,690			1,283
Other	—	(57	)	(25		)	—			(1		)	(26		)
Balance at June 30, 2018	1,015,122	(986	)	$	23,636		$	—		$	3,056		$	26,692
Balance at December 31, 2016	991,213	(819	)	$	24,758		$	609		$	1,245		$	26,612
Consolidated net income attributable to Southern Company	—	—		(723		)	—			—			(723		)
Other comprehensive income (loss)	—	—		(11		)	—			—			(11		)
Stock issued	9,129	—		417			—			—			417
Stock-based compensation	—	—		72			—			—			72
Cash dividends on common stock	—	—		(1,134		)	—			—			(1,134		)
Preference stock redemption	—	—		—			(150		)	—			(150		)
Contributions from noncontrolling interests	—	—		—			—			71			71
Distributions to noncontrolling interests	—	—		—			—			(40		)	(40		)
Net income attributable to noncontrolling interests	—	—		—			—			16			16
Reclassification from redeemable noncontrolling interests	—	—		—			—			114			114
Other	—	(49	)	(7		)	3			1			(3		)
Balance at June 30, 2017	1,000,342	(868	)	$	23,372		$	462		$	1,407		$	25,241

(a) Primarily related to Southern Power Company and excludes redeemable noncontrolling interests. See Note 10 to the financial statements of Southern Power in Item 8 of the Form 10-K for additional information.

(b) See Note (J) under "Southern Power – Sale of Solar Facility Interests" for additional information.

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Financing

6 Months Ended

Jun. 30, 2018

Debt Disclosure [Abstract]

FINANCING

FINANCING

Bank Credit Arrangements

Bank credit arrangements provide liquidity support to the registrants' commercial paper borrowings and the traditional electric operating companies' revenue bonds. The amount of variable rate revenue bonds of the traditional electric operating companies outstanding requiring liquidity support as of June 30, 2018 was approximately $1.5 billion (comprised of approximately $854 million at Alabama Power, $550 million at Georgia Power, $82 million at Gulf Power, and $40 million at Mississippi Power). In addition, at June 30, 2018, the traditional electric operating companies had approximately $482 million (comprised of approximately $120 million at Alabama Power, $232 million at Georgia Power, $37 million at Gulf Power, and $93 million at Mississippi Power) of revenue bonds outstanding that were required to be remarketed within the next 12 months. Subsequent to June 30, 2018, approximately $43 million of these pollution control revenue bonds of Mississippi Power were purchased and held by Mississippi Power. 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, 2018:

	Expires												Executable Term Loans		Expires Within One Year
Company	2018		2019		2020		2022		Total		Unused		One Year		Term Out		No Term Out
	(in millions)
Southern Company(a)	$	—	$	—	$	—	$	2,000	$	2,000	$	1,999	$	—	$	—	$	—
Alabama Power	2		31		500		800		1,333		1,333		—		—		33
Georgia Power	—		—		—		1,750		1,750		1,736		—		—		—
Gulf Power	20		25		235		—		280		280		45		45		—
Mississippi Power	100		—		—		—		100		100		—		—		100
Southern Power Company(b)	—		—		—		750		750		728		—		—		—
Southern Company Gas(c)	—		—		—		1,900		1,900		1,895		—		—		—
Other	—		30		—		—		30		30		—		—		30
Southern Company Consolidated	$	122	$	86	$	735	$	7,200	$	8,143	$	8,101	$	45	$	45	$	163

(a) Represents the Southern Company parent entity.

(b) Does not include Southern Power's $120 million continuing letter of credit facility for standby letters of credit expiring in 2019, of which $23 million remains unused at June 30, 2018.

(c) Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $1.4 billion of these arrangements. Southern Company Gas' committed credit arrangements also include $500 million for which Nicor Gas is the borrower and which is restricted for working capital needs of Nicor Gas.

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.

DOE Loan Guarantee Borrowings

See Note 6 to the financial statements of Southern Company and Georgia Power under "DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K for additional information regarding Georgia Power's Loan Guarantee Agreement.

On July 27, 2017, Georgia Power entered into an amendment to the Loan Guarantee Agreement (LGA Amendment) in connection with the DOE's consent to Georgia Power's entry into the Vogtle Services Agreement and the related intellectual property licenses (IP Licenses). Under the terms of the Loan Guarantee Agreement, upon termination of the Vogtle 3 and 4 Agreement, further advances are conditioned upon the DOE's approval of any agreements entered into in replacement of the Vogtle 3 and 4 Agreement. Under the terms of the LGA Amendment, Georgia Power will not request any advances unless and until certain conditions are satisfied, including (i) receipt of the DOE's approval of the Bechtel Agreement (together with the Vogtle Services Agreement and the IP Licenses, the Replacement EPC Arrangements) and (ii) Georgia Power's entry into a further amendment to the Loan Guarantee Agreement with the DOE to reflect the Replacement EPC Arrangements.

In September 2017, the DOE issued a conditional commitment to Georgia Power for up to approximately $1.67 billion in additional guaranteed loans under the Loan Guarantee Agreement. In June 2018, the DOE approved a request by Georgia Power to extend the conditional commitment to September 30, 2018. Any further extension must be approved by the DOE. Final approval and issuance of these additional loan guarantees by the DOE cannot be assured and are subject to the negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions, including the Vogtle Owners' votes to continue construction.

As of June 30, 2018, Georgia Power had $2.6 billion of borrowings outstanding under the multi-advance term loan facility (FFB Credit Facility) among Georgia Power, the DOE, and the FFB.

Under the Loan Guarantee Agreement, Georgia Power is subject to customary borrower affirmative and negative covenants and events of default. In addition, Georgia Power is subject to project-related reporting requirements and other project-specific covenants and events of default.

In the event certain mandatory prepayment events (including any decision not to continue construction of Plant Vogtle Units 3 and 4) occur, the FFB's commitment to make further advances under the FFB Credit Facility will terminate and Georgia Power will be required to prepay the outstanding principal amount of all borrowings under the FFB Credit Facility over a period of five years (with level principal amortization). Among other things, these mandatory prepayment events include (i) the termination of the Vogtle Services Agreement or rejection of the Vogtle Services Agreement in bankruptcy if Georgia Power does not maintain access to intellectual property rights under the IP Licenses; (ii) a decision by Georgia Power not to continue construction of Plant Vogtle Units 3 and 4; (iii) cancellation of Plant Vogtle Units 3 and 4 by the Georgia PSC, or by Georgia Power if authorized by the Georgia PSC; and (iv) cost disallowances by the Georgia PSC that could have a material adverse effect on completion of Plant Vogtle Units 3 and 4 or Georgia Power's ability to repay the outstanding borrowings under the FFB Credit Facility. Under certain circumstances, insurance proceeds and any proceeds from an event of taking must be applied to immediately prepay outstanding borrowings under the FFB Credit Facility. In addition, if Georgia Power discontinues construction of Plant Vogtle Units 3 and 4, Georgia Power would be obligated to immediately repay a portion of the outstanding borrowings under the FFB Credit Facility to the extent such outstanding borrowings exceed 70% of Eligible Project Costs, net of the proceeds received by Georgia Power under the Guarantee Settlement Agreement. Georgia Power also may voluntarily prepay outstanding borrowings under the FFB Credit Facility. Under the FFB Credit Facility, any prepayment (whether mandatory or optional) will be made with a make-whole premium or discount, as applicable.

Financing Activities

The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first six months of 2018:

Company	Senior Note Issuances		Senior Note Maturities, Redemptions, and Repurchases		Revenue Bond Maturities, Redemptions, and Repurchases		Other Long-Term Debt Redemptions and Maturities(*)
	(in millions)
Alabama Power	$	500	$	—	$	—	$	—
Georgia Power	—		1,000		398		104
Mississippi Power	600		—		—		900
Southern Power	—		350		—		420
Southern Company Gas	—		—		200		—
Other	—		—		—		7
Southern Company Consolidated	$	1,100	$	1,350	$	598	$	1,431

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

Southern Company

In March 2018, Southern Company entered into a $900 million short-term floating rate bank loan bearing interest based on one-month LIBOR. The proceeds were used for working capital and other general corporate purposes.

In April 2018, Southern Company borrowed $250 million pursuant to a short-term uncommitted bank credit arrangement, which bears interest at a rate agreed upon by Southern Company and the bank from time to time and is payable on no less than 30 days' demand by the bank.

In June 2018, Southern Company repaid at maturity two$100 million short-term floating rate bank term loans.

Alabama Power

In June 2018, Alabama Power issued $500 million aggregate principal amount of Series 2018A 4.30% Senior Notes due July 15, 2048. The proceeds were used to repay outstanding commercial paper and for general corporate purposes, including Alabama Power's continuous construction program.

Georgia Power

In January 2018, Georgia Power repaid its outstanding $150 million and $100 million floating rate bank loans due May 31, 2018 and October 26, 2018, respectively.

In March 2018, Georgia Power purchased and held $104.6 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 2013 and $173 million aggregate principal amount of Development Authority of Bartow County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Bowen Project), First Series 2009. Georgia Power may reoffer these bonds to the public at a later date.

In April 2018, Georgia Power purchased and held $55 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Fifth Series 1994. Georgia Power may reoffer these bonds to the public at a later date.

Also in April 2018, Georgia Power redeemed all $250 million aggregate principal amount of its Series 2008B 5.40% Senior Notes due June 1, 2018.

In May 2018, through cash tender offers, Georgia Power repurchased and retired $89 million of the $250 million aggregate principal amount outstanding of its Series 2007A 5.65% Senior Notes due March 1, 2037, $326 million of the $500 million aggregate principal amount outstanding of its Series 2009A 5.95% Senior Notes due February 1, 2039, and $335 million of the $600 million aggregate principal amount outstanding of its Series 2010B 5.40% Senior Notes due June 1, 2040, for an aggregate purchase price, excluding accrued and unpaid interest, of $902 million.

In June 2018, Georgia Power purchased and held $65 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Second Series 2008. Georgia Power may reoffer these bonds to the public at a later date.

Mississippi Power

In March 2018, Mississippi Power issued $300 million aggregate principal amount of Series 2018A Floating Rate Senior Notes due March 27, 2020 bearing interest based on three-month LIBOR and $300 million aggregate principal amount of Series 2018B 3.95% Senior Notes due March 30, 2028. In March 2018, Mississippi Power also entered into a $300 million short-term floating rate bank loan bearing interest based on one-month LIBOR, of which $200 million was repaid in the second quarter 2018 and $50 million was repaid subsequent to June 30, 2018. Mississippi Power used the proceeds from these financings to repay a $900 million unsecured term loan.

Southern Power

In May 2018, Southern Power entered into two short-term floating rate bank loans, each for an aggregate principal amount of $100 million, which bear interest based on one-month LIBOR.

In the second quarter 2018, Southern Power used a portion of the proceeds from the sale of a 33% equity interest in SPSH to repay $420 million aggregate principal amount of long-term floating rate bank loans and $350 million aggregate principal amount of Series 2015A 1.50% Senior Notes due June 1, 2018. See Note (J) under "Southern Power – Sale of Solar Facility Interests" for additional information.

Southern Company Gas

On January 4, 2018, Southern Company Gas issued a floating rate promissory note to Southern Company in an aggregate principal amount of $100 million bearing interest based on one-month LIBOR. On March 28, 2018, Southern Company Gas repaid this promissory note.

In the second quarter 2018, Pivotal Utility Holdings caused $200 million aggregate principal amount of gas facility revenue bonds to be redeemed. Also in the second quarter 2018, Pivotal Utility Holdings, as borrower, and Southern Company Gas, as guarantor, entered into a $181 million short-term delayed draw floating rate bank term loan bearing interest based on one-month LIBOR, which Pivotal Utility Holdings used to repay the gas facility revenue bonds. Subsequent to June 30, 2018, Pivotal Utility Holdings repaid this short-term loan.

In May 2018, Southern Company Gas Capital borrowed $95 million pursuant to a short-term uncommitted bank credit arrangement, guaranteed by Southern Company Gas, bearing interest at a rate agreed upon by Southern Company Gas Capital and the bank from time to time and payable on no less than 30 days' demand by the bank. The proceeds of the loan were used to pay down short-term debt. Subsequent to June 30, 2018, Southern Company Gas Capital repaid this loan.

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Retirement Benefits

6 Months Ended

Jun. 30, 2018

Retirement Benefits [Abstract]

RETIREMENT BENEFITS

RETIREMENT BENEFITS

On January 1, 2018, the qualified defined benefit pension plan of Southern Company Gas was merged into the qualified defined benefit pension plan of Southern Company. Following the plan merger, Southern Company has a qualified defined benefit, trusteed, pension plan covering substantially all employees, with the exception of employees at PowerSecure. The Southern Company qualified defined benefit pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). No mandatory contributions to the Southern Company qualified defined benefit pension plan are anticipated for the year ending December 31, 2018.

In addition, the Southern Company Gas non-qualified retirement plans were merged into the Southern Company non-qualified retirement plan (defined benefit and defined contribution). Following the non-qualified retirement plan mergers, Southern Company continues to provide certain non-qualified defined benefits for a select group of management and highly compensated employees, which are funded on a cash basis.

Furthermore, 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. Southern Company Gas also provides certain medical care and life insurance benefits for eligible retired employees through a postretirement benefit plan. Southern Company Gas has a separate unfunded supplemental retirement health care plan that provides medical care and life insurance benefits to employees of discontinued businesses.

As indicated in Note (A), the registrants adopted ASU 2017-07 as of January 1, 2018. ASU 2017-07 requires that an employer report the service cost component of net periodic benefit costs in the same line item or items as other compensation costs and requires the other components of net periodic benefit costs to be separately presented in the statements of income outside of income from operations. The presentation requirements of ASU 2017-07 have been applied retrospectively with the service cost component of net periodic benefit costs included in operations and maintenance and all other components of net periodic benefit costs included in other income (expense), net in the statements of income for the three and six months ended June 30, 2017.

With respect to the presentation requirements, the registrants have used the practical expedient provided by ASU 2017-07, which permits an employer to use the amounts disclosed in its retirement benefits footnote for prior comparative periods as the estimation basis for applying the retrospective presentation requirements to those periods. The amounts of the other components of net periodic benefit costs reclassified for the prior period are presented in the following tables.

See Note 2 to the financial statements of each registrant in Item 8 of the Form 10-K for additional information.

Components of the net periodic benefit costs for the three and six months ended June 30, 2018 and 2017 are presented in the following tables.

Three Months Ended June 30, 2018	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power			Southern Power			Southern Company Gas
	(in millions)
Pension Plans
Service cost	$	89		$	20		$	21		$	4		$	4		$	2		$	8
Interest cost	116			25			35			5			5			2			9
Expected return on plan assets	(235		)	(53		)	(74		)	(10		)	(10		)	(2		)	(17		)
Amortization:
Prior service costs	1			1			1			—			—			—			—
Regulatory asset	—			—			—			—			—			—			4
Net (gain)/loss	54			13			17			3			2			—			3
Net periodic pension cost (income)	$	25		$	6		$	—		$	2		$	1		$	2		$	7
Postretirement Benefits
Service cost	$	6		$	2		$	1		$	1		$	1		$	—		$	—
Interest cost	18			4			7			—			1			—			3
Expected return on plan assets	(17		)	(7		)	(7		)	(1		)	(1		)	—			(2		)
Amortization:
Prior service costs	1			1			1			—			—			—			—
Regulatory asset	—			—			—			—			—			—			2
Net (gain)/loss	4			1			2			—			—			—			—
Net periodic postretirement benefit cost	$	12		$	1		$	4		$	—		$	1		$	—		$	3

Six Months Ended June 30, 2018	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power			Southern Power			Southern Company Gas
	(in millions)
Pension Plans
Service cost	$	179		$	39		$	43		$	8		$	8		$	4		$	16
Interest cost	232			50			70			10			10			3			19
Expected return on plan assets	(471		)	(104		)	(148		)	(20		)	(20		)	(5		)	(35		)
Amortization:
Prior service costs	2			1			1			—			—			—			(1		)
Regulatory asset	—			—			—			—			—			—			7
Net (gain)/loss	107			27			34			5			5			1			6
Net periodic pension cost (income)	$	49		$	13		$	—		$	3		$	3		$	3		$	12
Postretirement Benefits
Service cost	$	12		$	3		$	3		$	1		$	1		$	—		$	1
Interest cost	37			8			14			1			2			—			5
Expected return on plan assets	(34		)	(13		)	(13		)	(1		)	(1		)	—			(4		)
Amortization:
Regulatory asset	3			2			1			—			—			—			3
Net (gain)/loss	7			1			4			—			—			—			—
Net periodic postretirement benefit cost	$	25		$	1		$	9		$	1		$	2		$	—		$	5

Three Months Ended June 30, 2017(*)	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power			Southern Company Gas
	(in millions)
Pension Plans
Service cost	$	74		$	16		$	18		$	4		$	3		$	5
Interest cost	113			24			35			5			5			10
Expected return on plan assets	(225		)	(49		)	(70		)	(9		)	(10		)	(17		)
Amortization:
Prior service costs	3			—			1			—			1			(1		)
Net (gain)/loss	41			11			14			1			2			5
Net periodic pension cost (income)	$	6		$	2		$	(2	)	$	1		$	1		$	2
Postretirement Benefits
Service cost	$	6		$	2		$	1		$	1		$	1		$	—
Interest cost	20			4			8			—			1			2
Expected return on plan assets	(17		)	(8		)	(6		)	(1		)	(1		)	(1		)
Amortization:
Prior service costs	1			1			1			—			—			—
Net (gain)/loss	5			1			1			—			—			1
Net periodic postretirement benefit cost	$	15		$	—		$	5		$	—		$	1		$	2

(*) Excludes Southern Power since Southern Power did not participate in the qualified pension and postretirement benefit plans until December 2017.

Six Months Ended June 30, 2017(*)	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power			Southern Company Gas
	(in millions)
Pension Plans
Service cost	$	147		$	32		$	37		$	7		$	7		$	11
Interest cost	227			48			69			10			10			20
Expected return on plan assets	(449		)	(98		)	(141		)	(19		)	(20		)	(35		)
Amortization:
Prior service costs	6			1			2			—			1			(1		)
Net (gain)/loss	81			21			28			3			4			10
Net periodic pension cost (income)	$	12		$	4		$	(5	)	$	1		$	2		$	5
Postretirement Benefits
Service cost	$	12		$	3		$	3		$	1		$	1		$	1
Interest cost	40			9			15			1			2			5
Expected return on plan assets	(33		)	(14		)	(12		)	(1		)	(1		)	(3		)
Amortization:
Prior service costs	3			2			1			—			—			(1		)
Net (gain)/loss	7			1			3			—			—			2
Net periodic postretirement benefit cost	$	29		$	1		$	10		$	1		$	2		$	4

(*) Excludes Southern Power since Southern Power did not participate in the qualified pension and postretirement benefit plans until December 2017.

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Income Taxes

6 Months Ended

Jun. 30, 2018

Income Tax Disclosure [Abstract]

INCOME TAXES

INCOME TAXES

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

Federal Tax Reform Legislation

Following the enactment of the Tax Reform Legislation, the SEC staff issued Staff Accounting Bulletin 118 – "Income Tax Accounting Implications of the Tax Cuts and Jobs Act" (SAB 118), which provides for a measurement period of up to one year from the enactment date to complete accounting under GAAP for the tax effects of the legislation. Due to the complex and comprehensive nature of the enacted tax law changes, and their application under GAAP, the registrants consider all amounts recorded in the financial statements as a result of the Tax Reform Legislation to be "provisional" as discussed in SAB 118 and subject to revision. Each of the registrants is awaiting additional guidance from industry and income tax authorities in order to finalize its accounting. The ultimate impact of the Tax Reform Legislation on deferred income tax assets and liabilities and the related regulatory assets and liabilities cannot be determined at this time. See Note (B) under "Regulatory Matters" for additional information.

Current and Deferred Income Taxes

Tax Credit Carryforwards

Southern Company had federal ITC and PTC carryforwards (primarily related to Southern Power) totaling $2.3 billion as of June 30, 2018 compared to $2.1 billion as of December 31, 2017.

The federal ITC and PTC carryforwards begin expiring in 2034 and 2032, respectively, but are expected to be fully utilized by 2021. The estimated tax credit utilization reflects the 2018 abandonment loss related to certain Kemper County energy facility expenditures as well as the projected taxable gains on the various sale transactions described in Note (J) and "Legal Entity Reorganizations" herein. The expected utilization of tax credit carryforwards could be further delayed by numerous factors, including the acquisition of additional renewable projects and increased generation at existing wind facilities. The ultimate outcome of these matters cannot be determined at this time.

Effective Tax Rate

Each registrant's effective tax rate for the six months ended June 30, 2018 varied significantly as compared to the corresponding period in 2017 due to the 14% lower 2018 federal tax rate resulting from the Tax Reform Legislation.

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 benefit rate was (3.2)% for the six months ended June 30, 2018 compared to a benefit rate of (28.6)% for the corresponding period in 2017. The effective tax rate increase was primarily due to the $3.1 billion pre-tax loss on the Kemper IGCC, net of the non-deductible AFUDC equity portion, recorded in 2017, partially offset by the $1.1 billion pre-tax loss related to Plant Vogtle Units 3 and 4 in 2018, the reduction in the federal corporate income tax rate and the benefit from the flowback of excess deferred income taxes as a result of the Tax Reform Legislation, as well as net state income tax benefits related to changes in state apportionment rates arising from the reorganization of Southern Power's legal entities as discussed further herein. See Note 3 to the financial statements of Southern Company under "Kemper County Energy Facility" in Item 8 of the Form 10-K and Note (B) under "Kemper County Energy Facility" for additional information regarding the Kemper IGCC and Note (B) under "Nuclear Construction" for additional information regarding Plant Vogtle Units 3 and 4. See Note (B) under "Regulatory Matters" for additional information on the flowback of excess deferred income taxes.

Southern Company recognizes PTCs when wind energy is generated and sold (using the prescribed KWH rate in applicable federal and state statutes), which may differ significantly from amounts computed on a quarterly basis using an overall estimated annual effective income tax rate. Southern Company uses this method of recognition since the amount of PTCs can be significantly impacted by wind generation. This method can significantly affect the effective income tax rate for the period depending on the amount of pretax income.

Alabama Power

Alabama Power's effective tax rate was 22.8% for the six months ended June 30, 2018 compared to 40.2% for the corresponding period in 2017. The effective tax rate decrease was primarily due to the reduction in the federal corporate income tax rate and the benefit from the flowback of excess deferred income taxes as a result of the Tax Reform Legislation. See Note (B) under "Regulatory Matters – Alabama Power" for additional information.

Georgia Power

Georgia Power's effective tax benefit rate was (53.5)% for the six months ended June 30, 2018 compared to an effective tax rate of 36.6% for the corresponding period in 2017. The effective tax rate decrease was primarily due to the $1.1 billion pre-tax loss related to the estimated probable loss on Plant Vogtle Units 3 and 4 recorded in 2018, partially offset by the reduction in the federal corporate income tax rate. See Note (B) under "Nuclear Construction" for additional information.

Gulf Power

Gulf Power's effective tax rate was 3.3% for the six months ended June 30, 2018 compared to 39.8% for the corresponding period in 2017. The effective tax rate decrease was primarily due to the reduction in the federal corporate income tax rate and the benefit from the flowback of excess deferred income taxes as a result of the Tax Reform Legislation. See Note (B) under "Regulatory Matters – Gulf Power" for additional information.

Mississippi Power

Mississippi Power's effective tax rate was 18.7% for the six months ended June 30, 2018 compared to a benefit rate of (30.5)% for the corresponding period in 2017. The effective tax rate increase was primarily due to the $3.1 billion pre-tax loss on the Kemper IGCC, net of the non-deductible AFUDC equity portion, recorded in 2017, partially offset by the reduction in the federal corporate income tax rate as a result of the Tax Reform Legislation. See Note (B) under "Regulatory Matters – Mississippi Power" for additional information.

Southern Power

Southern Power's effective tax benefit rate was (1,386.5)% for the six months ended June 30, 2018 compared to a benefit rate of (114.7)% for the corresponding period in 2017. The effective tax rate decrease was primarily due to lower earnings before income taxes resulting from a $119 million asset impairment charge related to the sale of Southern Power's equity interests in two natural gas-fired operating facilities, Plant Oleander and Plant Stanton Unit A (together, the Florida Plants) described in Note (J) under "Southern Power – Sale of Florida Plants," as well as the reduction in the federal corporate income tax rate and the net state income tax benefits related to certain changes in apportionment rates arising from the reorganization of Southern Power's legal entities as described below.

Southern Power recognizes PTCs when wind energy is generated and sold (using the prescribed KWH rate in applicable federal and state statutes), which may differ significantly from amounts computed on a quarterly basis using an overall estimated annual effective income tax rate. Southern Power uses this method of recognition since the amount of PTCs can be significantly impacted by wind generation. This method can significantly affect the effective income tax rate for the period depending on the amount of pretax income.

Southern Company Gas

Southern Company Gas' effective tax rate was 39.1% for the six months ended June 30, 2018 compared to 38.5% for the corresponding period in 2017. This increase was primarily related to income taxes recorded related to the sale of Pivotal Home Solutions, including the reduction in deferred tax expense as a result of treating the sale as an asset sale for tax purposes, partially offset by the reduction in the federal corporate income tax rate and the benefit from the flowback of excess deferred income taxes as a result of the Tax Reform Legislation. See Note (B) under "Regulatory Matters – Southern Company Gas" and Note (J) under "Southern Company Gas – Sale of Pivotal Home Solutions" for additional information.

Legal Entity Reorganizations

In March 2018, Southern Power substantially completed a legal entity reorganization of various direct and indirect subsidiaries that own and operate substantially all of its solar facilities, including certain subsidiaries owned in partnership with various third parties. The reorganization resulted in net state tax benefits related to certain changes in apportionment rates totaling approximately $50 million, which were recorded in the first quarter 2018. In April 2018, Southern Power completed the final stage of the reorganization resulting in additional net state tax benefits of approximately $4 million.

Southern Power is pursuing the sale of a noncontrolling interest in a portfolio of eight operating wind facilities through the use of third-party tax equity, which, if successful, is expected to close in the fourth quarter 2018. In the third quarter 2018, various direct and indirect subsidiaries of Southern Power that own and operate these wind facilities are expected to be reorganized under a new holding company in which the tax equity partner would invest. The reorganization is expected to result in estimated net state tax benefits totaling approximately $10 million related to certain changes in apportionment rates. The ultimate outcome of this matter cannot be determined at this time.

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.

The registrants had no unrecognized tax benefits as of June 30, 2018. 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 income tax returns through 2016, as well as the pre-Merger Southern Company Gas tax returns. Southern Company is a participant in the Compliance Assurance Process of the IRS. The audits for Southern Company's state income tax returns have either been concluded, or the statute of limitations has expired, for years prior to 2011.

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Derivatives

6 Months Ended

Jun. 30, 2018

Derivative Instruments and Hedging Activities Disclosure [Abstract]

DERIVATIVES

DERIVATIVES

Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas are exposed to market risks, including commodity price risk, interest rate risk, weather risk, and occasionally foreign currency exchange rate risk. To manage the volatility attributable to these exposures, each company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to each company's policies in areas such as counterparty exposure and risk management practices. Southern Company Gas' wholesale gas operations use various contracts in its commercial activities that generally meet the definition of derivatives. For the traditional electric operating companies, Southern Power, and Southern Company Gas' other businesses, 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 net basis. See Note (D) 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.

The registrants adopted ASU 2017-12 as of January 1, 2018. See Note (A) under "Recently Adopted Accounting Standards – Other" for additional information.

Energy-Related Derivatives

Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas enter into energy-related derivatives to hedge exposures to electricity, natural gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the traditional electric operating companies and the natural gas distribution utilities have limited exposure to market volatility in energy-related commodity prices. Each of the traditional electric operating companies and certain of the natural gas distribution utilities of Southern Company Gas manage fuel-hedging programs, implemented per the guidelines of their respective state PSCs or other applicable state regulatory agencies, through the use of financial derivative contracts, which is expected to continue to mitigate price volatility. The Florida PSC approved a moratorium on Gulf Power's fuel-hedging program until January 1, 2021. The moratorium does not have an impact on the recovery of existing hedges entered into under the previously-approved hedging program. The traditional electric operating companies (with respect to wholesale generating capacity) and Southern Power have limited exposure to market volatility in energy-related commodity prices 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 capacity is used to sell electricity. Southern Company Gas retains exposure to price changes that can, in a volatile energy market, be material and can adversely affect its results of operations.

Southern Company Gas also enters into weather derivative contracts as economic hedges of operating margins in the event of warmer-than-normal weather. Exchange-traded options are carried at fair value, with changes reflected in operating revenues. Non-exchange-traded options are accounted for using the intrinsic value method. Changes in the intrinsic value for non-exchange-traded contracts are reflected in operating revenues.

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' and the natural gas distribution utilities' 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 and in the same income statement line item as the earnings effect of the hedged transactions.

• 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 and natural gas industries. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered.

At June 30, 2018, 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(*)	701	2022	2029
Alabama Power	82	2022	—
Georgia Power	174	2022	—
Gulf Power	13	2020	—
Mississippi Power	66	2022	—
Southern Power	14	2020	—
Southern Company Gas(*)	352	2020	2029

(*) Southern Company's and Southern Company Gas' derivative instruments include both long and short natural gas positions. A long position is a contract to purchase natural gas and a short position is a contract to sell natural gas. Southern Company Gas' volume represents the net of long natural gas positions of 3.9 billion mmBtu and short natural gas positions of 3.6 billion mmBtu as of June 30, 2018, which is also included in Southern Company's total volume.

In addition to the volumes discussed above, 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 17 million mmBtu for Southern Company, 3 million mmBtu for Alabama Power, 6 million mmBtu for Georgia Power, 1 million mmBtu for Gulf Power, 2 million mmBtu for Mississippi Power, and 5 million mmBtu for Southern Power.

For cash flow hedges of energy-related derivatives, the amounts expected to be reclassified from accumulated OCI to earnings for the next 12-month period ending June 30, 2019 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 derivatives' fair value gains or losses are recorded in OCI and are reclassified into earnings at the same time and presented on the same income statement line item as the earnings effect of the hedged transactions. 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 on the same income statement line item. Fair value gains or losses on derivatives that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.

At June 30, 2018, 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, 2018
	(in millions)					(in millions)
Fair Value Hedges of Existing Debt
Southern Company(*)	$	300	2.75%	3-month LIBOR + 0.92%	June 2020	$	(6	)
Southern Company(*)	1,500		2.35%	1-month LIBOR + 0.87%	July 2021	(57		)
Georgia Power	500		1.95%	3-month LIBOR + 0.76%	December 2018	(3		)
Georgia Power	200		4.25%	3-month LIBOR + 2.46%	December 2019	(3		)
Southern Company Consolidated	$	2,500				$	(69	)

(*) Represents the Southern Company parent entity.

The estimated pre-tax gains (losses) related to interest rate derivatives expected to be reclassified from accumulated OCI to interest expense for the next 12-month period ending June 30, 2019 are $(18) million for Southern Company and immaterial for all other registrants. Southern Company and certain subsidiaries have deferred gains and losses 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 derivatives' fair value gains or losses are recorded in OCI and are reclassified into earnings at the same time and on the same income statement line as the earnings effect of the hedged transactions, including foreign currency gains or losses arising from changes in the U.S. currency exchange rates. The derivatives employed as hedging instruments are structured to minimize ineffectiveness.

At June 30, 2018, 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, 2018
	(in millions)			(in millions)				(in millions)
Cash Flow Hedges of Existing Debt
Southern Power	$	677	2.95%	€	600	1.00%	June 2022	$	54
Southern Power	564		3.78%	500		1.85%	June 2026	55
Total	$	1,241		€	1,100			$	109

The estimated pre-tax gains (losses) related to foreign currency derivatives that will be reclassified from accumulated OCI to earnings for the next 12-month period ending June 30, 2019 are $(23) million for Southern Company and Southern Power.

Derivative Financial Statement Presentation and Amounts

Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas enter into derivative contracts that 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. Southern Company and certain subsidiaries also utilize master netting agreements to mitigate exposure to counterparty credit risk. These agreements may contain provisions that permit netting across product lines and against cash collateral. The fair value amounts of derivative assets and liabilities on the balance sheet are presented net to the extent that there are netting arrangements or similar agreements with the counterparties.

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

	As of June 30, 2018						As of December 31, 2017
Derivative Category and Balance Sheet Location	Assets			Liabilities			Assets			Liabilities
	(in millions)						(in millions)
Southern Company
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	16		$	12		$	10		$	43
Other deferred charges and assets/Other deferred credits and liabilities	5			27			7			24
Assets held for sale, current/Liabilities held for sale, current	—			8			—			—
Assets held for sale/Liabilities held for sale	—			4			—			—
Total derivatives designated as hedging instruments for regulatory purposes	$	21		$	51		$	17		$	67
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Other current assets/Other current liabilities	$	2		$	3		$	3		$	14
Other deferred charges and assets/Other deferred credits and liabilities	1			1			—			—
Interest rate derivatives:
Other current assets/Other current liabilities	—			15			1			4
Other deferred charges and assets/Other deferred credits and liabilities	—			53			—			34
Foreign currency derivatives:
Other current assets/Other current liabilities	—			23			—			23
Other deferred charges and assets/Other deferred credits and liabilities	132			—			129			—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	135		$	95		$	133		$	75
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets/Other current liabilities	$	239		$	272		$	380		$	437
Other deferred charges and assets/Other deferred credits and liabilities	189			246			170			215
Total derivatives not designated as hedging instruments	$	428		$	518		$	550		$	652
Gross amounts recognized	$	584		$	664		$	700		$	794
Gross amounts offset(a)	$	(306	)	$	(489	)	$	(405	)	$	(598	)
Net amounts recognized in the Balance Sheets(b)	$	278		$	175		$	295		$	196

	As of June 30, 2018						As of December 31, 2017
Derivative Category and Balance Sheet Location	Assets			Liabilities			Assets			Liabilities
	(in millions)						(in millions)
Alabama Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	6		$	3		$	2		$	6
Other deferred charges and assets/Other deferred credits and liabilities	2			6			2			4
Total derivatives designated as hedging instruments for regulatory purposes	$	8		$	9		$	4		$	10
Gross amounts recognized	$	8		$	9		$	4		$	10
Gross amounts offset	$	(4	)	$	(4	)	$	(4	)	$	(4	)
Net amounts recognized in the Balance Sheets	$	4		$	5		$	—		$	6
Georgia Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	5		$	5		$	2		$	9
Other deferred charges and assets/Other deferred credits and liabilities	2			14			4			10
Total derivatives designated as hedging instruments for regulatory purposes	$	7		$	19		$	6		$	19
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current assets/Other current liabilities	$	—		$	5		$	—		$	4
Other deferred charges and assets/Other deferred credits and liabilities	—			1			—			1
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	—		$	6		$	—		$	5
Gross amounts recognized	$	7		$	25		$	6		$	24
Gross amounts offset	$	(7	)	$	(7	)	$	(6	)	$	(6	)
Net amounts recognized in the Balance Sheets	$	—		$	18		$	—		$	18
Gulf Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	—		$	8		$	—		$	14
Other deferred charges and assets/Other deferred credits and liabilities	—			4			—			7
Total derivatives designated as hedging instruments for regulatory purposes	$	—		$	12		$	—		$	21
Gross amounts recognized	$	—		$	12		$	—		$	21
Gross amounts offset	$	—		$	—		$	—		$	—
Net amounts recognized in the Balance Sheets	$	—		$	12		$	—		$	21

	As of June 30, 2018						As of December 31, 2017
Derivative Category and Balance Sheet Location	Assets			Liabilities			Assets			Liabilities
	(in millions)						(in millions)
Mississippi Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	2		$	3		$	1		$	6
Other deferred charges and assets/Other deferred credits and liabilities	1			6			1			3
Total derivatives designated as hedging instruments for regulatory purposes	$	3		$	9		$	2		$	9
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current assets/Other current liabilities	$	—		$	—		$	1		$	—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	—		$	—		$	1		$	—
Gross amounts recognized	$	3		$	9		$	3		$	9
Gross amounts offset	$	(2	)	$	(2	)	$	(2	)	$	(2	)
Net amounts recognized in the Balance Sheets	$	1		$	7		$	1		$	7
Southern Power
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Other current assets/Other current liabilities	$	2		$	2		$	3		$	11
Other deferred charges and assets/Other deferred credits and liabilities	1			1			—			—
Foreign currency derivatives:
Other current assets/Other current liabilities	—			23			—			23
Other deferred charges and assets/Other deferred credits and liabilities	132			—			129			—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	135		$	26		$	132		$	34
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets/Other current liabilities	$	—		$	—		$	—		$	2
Gross amounts recognized	$	135		$	26		$	132		$	36
Gross amounts offset	$	(2	)	$	(2	)	$	(3	)	$	(3	)
Net amounts recognized in the Balance Sheets	$	133		$	24		$	129		$	33

	As of June 30, 2018						As of December 31, 2017
Derivative Category and Balance Sheet Location	Assets			Liabilities			Assets			Liabilities
	(in millions)						(in millions)
Southern Company Gas
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Assets from risk management activities/Liabilities from risk management activities-current	$	3		$	1		$	5		$	8
Other deferred charges and assets/Other deferred credits and liabilities	—			1			—			—
Total derivatives designated as hedging instruments for regulatory purposes	$	3		$	2		$	5		$	8
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Assets from risk management activities/Liabilities from risk management activities-current	$	—		$	1		$	—		$	3
Derivatives not designated as hedging instruments
Energy-related derivatives:
Assets from risk management activities/Liabilities from risk management activities-current	$	239		$	272		$	379		$	434
Other deferred charges and assets/Other deferred credits and liabilities	189			246			170			215
Total derivatives not designated as hedging instruments	$	428		$	518		$	549		$	649
Gross amounts of recognized	$	431		$	521		$	554		$	660
Gross amounts offset(a)	$	(291	)	$	(474	)	$	(390	)	$	(583	)
Net amounts recognized in the Balance Sheets(b)	$	140		$	47		$	164		$	77

(a) Gross amounts offset include cash collateral held on deposit in broker margin accounts of $183 million and $193 million as of June 30, 2018 and December 31, 2017, respectively.

(b) Net amounts of derivative instruments outstanding exclude premium and intrinsic value associated with weather derivatives of $3 million and $11 million as of June 30, 2018 and December 31, 2017, respectively.

At June 30, 2018 and December 31, 2017, 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 in the Balance Sheet at June 30, 2018
Derivative Category and Balance Sheet Location	Southern Company(*)			Alabama Power			Georgia Power			Gulf Power			Mississippi Power			Southern Company Gas(*)
	(in millions)
Energy-related derivatives:
Other regulatory assets, current	$	(4	)	$	(1	)	$	(1	)	$	(8	)	$	(1	)	$	(1	)
Other regulatory assets, deferred	(20		)	(4		)	(11		)	(4		)	(5		)	—
Assets held for sale, current	(8		)	—			—			—			—			—
Assets held for sale	(4		)	—			—			—			—			—
Other regulatory liabilities, current	8			4			—			—			—			4
Total energy-related derivative gains (losses)	$	(28	)	$	(1	)	$	(12	)	$	(12	)	$	(6	)	$	3

(*) Fair value gains and losses recorded in regulatory assets and liabilities include cash collateral held on deposit in broker margin accounts of $2 million at June 30, 2018.

Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at December 31, 2017
Derivative Category and Balance Sheet Location	Southern Company(*)			Alabama Power			Georgia Power			Gulf Power			Mississippi Power			Southern Company Gas(*)
	(in millions)
Energy-related derivatives:
Other regulatory assets, current	$	(34	)	$	(4	)	$	(7	)	$	(14	)	$	(5	)	$	(4	)
Other regulatory assets, deferred	(18		)	(3		)	(6		)	(7		)	(2		)	—
Other regulatory liabilities, current	7			—			—			—			—			7
Other regulatory liabilities, deferred	1			1			—			—			—			—
Total energy-related derivative gains (losses)	$	(44	)	$	(6	)	$	(13	)	$	(21	)	$	(7	)	$	3

(*) Fair value gains and losses recorded in regulatory assets and liabilities include cash collateral held on deposit in broker margin accounts of $6 million at December 31, 2017.

For the three and six months ended June 30, 2018 and 2017, the pre-tax effects of cash flow hedge accounting on accumulated OCI were as follows:

Gain (Loss) Recognized in OCI on Derivative	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2018			2017			2018			2017
	(in millions)						(in millions)
Southern Company
Energy-related derivatives	$	—		$	(9	)	$	12		$	(20	)
Interest rate derivatives	—			(1		)	(2		)	(1		)
Foreign currency derivatives	(73		)	71			(21		)	67
Total	$	(73	)	$	61		$	(11	)	$	46
Southern Power
Energy-related derivatives	$	(1	)	$	(7	)	$	10		$	(15	)
Foreign currency derivatives	(73		)	71			(21		)	67
Total	$	(74	)	$	64		$	(11	)	$	52
Southern Company Gas
Energy-related derivatives	$	1		$	(2	)	$	2		$	(4	)

For the three and six months ended June 30, 2018 and 2017, the pre-tax effects of energy-related derivatives and interest rate derivatives designated as cash flow hedging instruments on accumulated OCI were immaterial for the other registrants.

For the three and six months ended June 30, 2017, there was no material ineffectiveness recorded in earnings for any registrant. Upon the adoption of ASU 2017-12, beginning in 2018, ineffectiveness was no longer separately measured and recorded in earnings. See Note (A) for additional information.

For the three and six months ended June 30, 2018 and 2017, the pre-tax effects of cash flow and fair value hedge accounting on income were as follows:

Location and Amount of Gain (Loss) Recognized in Income on Cash Flow and Fair Value Hedging Relationships	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2018			2017			2018			2017
	(in millions)						(in millions)
Southern Company
Depreciation and amortization	$	783		$	754		$	1,552		$	1,469
Gain (loss) on cash flow hedges(a)
Energy-related derivatives	1			(2		)	2			(6		)
Interest expense, net of amounts capitalized	(470		)	(424		)	(928		)	(840		)
Gain (loss) on cash flow hedges(a)
Interest rate derivatives	(6		)	(5		)	(11		)	(10		)
Foreign currency derivatives	(7		)	(5		)	(12		)	(12		)
Gain (loss) on fair value hedges(b)
Interest rate derivatives	(7		)	7			(31		)	(1		)
Other income (expense), net	78			52			138			98
Gain (loss) on cash flow hedges(a)(c)
Foreign currency derivatives	(73		)	79			(37		)	96
Cost of natural gas	228			232			949			951
Gain (loss) on cash flow hedges(a)
Energy-related derivatives	—			—			(2		)	—
Alabama Power
Interest expense, net of amounts capitalized	$	(80	)	$	(77	)	$	(158	)	$	(153	)
Gain (loss) on cash flow hedges(a)
Interest rate derivatives	(1		)	(2		)	(3		)	(3		)
Georgia Power
Interest expense, net of amounts capitalized	$	(102	)	$	(104	)	$	(208	)	$	(205	)
Gain (loss) on cash flow hedges(a)
Interest rate derivatives	(2		)	(1		)	(3		)	(3		)
Gain (loss) on fair value hedges(b)
Interest rate derivatives	2			—			(1		)	(1		)
Mississippi Power
Interest expense, net of amounts capitalized	$	(21	)	$	(17	)	$	(39	)	$	(37	)
Gain (loss) on cash flow hedges(a)
Interest rate derivatives	(1		)	—			(1		)	(1		)

Location and Amount of Gain (Loss) Recognized in Income on Cash Flow and Fair Value Hedging Relationships	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2018			2017			2018			2017
	(in millions)						(in millions)
Southern Power
Depreciation and amortization	$	125		$	129		$	240		$	247
Gain (loss) on cash flow hedges(a)
Energy-related derivatives	1			(2		)	2			(6		)
Interest expense, net of amounts capitalized	(46		)	(48		)	(93		)	(97		)
Gain (loss) on cash flow hedges(a)
Foreign currency derivatives	(7		)	(5		)	(12		)	(12		)
Other income (expense), net	2			2			5			(2		)
Gain (loss) on cash flow hedges(a)(c)
Foreign currency derivatives	(73		)	79			(37		)	96
Southern Company Gas
Cost of natural gas	$	228		$	232		$	949		$	951
Gain (loss) on cash flow hedges(a)
Energy-related derivatives	—			—			(2		)	—

(a) Amounts reflect gains or losses on cash flow hedges that were reclassified from accumulated OCI into income.

(b) For fair value hedges presented above, generally changes in the fair value of the derivative contracts are equal to changes in the fair value of the underlying debt and have no material impact on income.

(c) The reclassification from accumulated OCI into other income (expense), net completely offsets currency gains and losses arising from changes in the U.S. currency exchange rates used to record the euro-denominated notes.

For the three and six months ended June 30, 2018 and 2017, the pre-tax effects of cash flow hedge accounting on income for interest rate derivatives were immaterial for Gulf Power and Southern Company Gas.

As of June 30, 2018 and December 31, 2017, the following amounts were recorded on the balance sheets related to cumulative basis adjustments for fair value hedges:

	Carrying Amount of the Hedged Item						Cumulative Amount of Fair Value Hedging Adjustment included in Carrying Amount of the Hedged Item
Balance Sheet Location of Hedged Items	As of June 30, 2018			As of December 31, 2017			As of June 30, 2018		As of December 31, 2017
	(in millions)						(in millions)
Southern Company
Securities due within one year	$	(497	)	$	(746	)	$	3	$	3
Long-term Debt	(2,528		)	(2,553		)	63		35
Georgia Power
Securities due within one year	$	(497	)	$	(746	)	$	3	$	3
Long-term Debt	(497		)	(498		)	3		1

For the three and six months ended June 30, 2018 and 2017, the pre-tax effects of energy-related derivatives not designated as hedging instruments on the statements of income were as follows:

		Gain (Loss)
		Three Months Ended June 30,						Six Months Ended June 30,
Derivatives in Non-Designated Hedging Relationships	Statements of Income Location	2018			2017			2018			2017
		(in millions)						(in millions)
Southern Company
Energy-related derivatives:	Natural gas revenues(*)	$	(28	)	$	16		$	(43	)	$	65
	Cost of natural gas	2			(2		)	4			(4		)
Total derivatives in non-designated hedging relationships		$	(26	)	$	14		$	(39	)	$	61
Southern Company Gas
Energy-related derivatives:	Natural gas revenues(*)	$	(28	)	$	16		$	(43	)	$	65
	Cost of natural gas	2			(2		)	4			(4		)
Total derivatives in non-designated hedging relationships		$	(26	)	$	14		$	(39	)	$	61

(*) Excludes gains (losses) recorded in natural gas revenues associated with weather derivatives of $15 million for the six months ended June 30, 2017 and immaterial amounts for all other periods presented.

For the three and six months ended June 30, 2018 and 2017, the pre-tax effects of energy-related derivatives and interest rate derivatives not designated as hedging instruments were immaterial for the traditional electric operating companies and Southern Power.

Contingent Features

Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas 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, 2018, the registrants had no collateral posted with derivative counterparties to satisfy these arrangements.

For the registrants with interest rate derivatives at June 30, 2018, the fair value of interest rate derivative liabilities with contingent features and the maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, was immaterial. At June 30, 2018, the fair value of energy-related derivative liabilities with contingent features and the maximum potential collateral requirements arising from the credit-risk-related contingent features, at a rating below BBB- and/or Baa3, were immaterial for all registrants. The maximum potential collateral requirements arising from the credit-risk-related contingent features for the traditional electric operating companies and Southern Power 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.

Alabama Power and Southern Power maintain accounts with certain regional transmission organizations to facilitate financial derivative transactions. Based on the value of the positions in these accounts and the associated margin requirements, Alabama Power and Southern Power may be required to post collateral. At June 30, 2018, cash collateral posted in these accounts was immaterial. Southern Company Gas maintains accounts with brokers or the clearing houses of certain exchanges to facilitate financial derivative transactions. Based on the value of the positions in these accounts and the associated margin requirements, Southern Company Gas may be required to deposit cash into these accounts. At June 30, 2018, cash collateral held on deposit in broker margin accounts was $183 million.

Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas are exposed to losses related to financial instruments in the event of counterparties' nonperformance. Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas 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, Southern Power, and Southern Company Gas 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', Southern Power's, and Southern Company Gas' exposure to counterparty credit risk. Southern Company Gas may require counterparties to pledge additional collateral when deemed necessary.

In addition, Southern Company Gas conducts credit evaluations and obtains appropriate internal approvals for the counterparty's line of credit before any transaction with the counterparty is executed. In most cases, the counterparty must have an investment grade rating, which includes a minimum long-term debt rating of Baa3 from Moody's and BBB- from S&P. Generally, Southern Company Gas requires credit enhancements by way of a guaranty, cash deposit, or letter of credit for transaction counterparties that do not have investment grade ratings.

Southern Company Gas also utilizes master netting agreements whenever possible to mitigate exposure to counterparty credit risk. When Southern Company Gas is engaged in more than one outstanding derivative transaction with the same counterparty and it also has a legally enforceable netting agreement with that counterparty, the "net" mark-to-market exposure represents the netting of the positive and negative exposures with that counterparty and a reasonable measure of Southern Company Gas' credit risk. Southern Company Gas also uses other netting agreements with certain counterparties with whom it conducts significant transactions. Master netting agreements enable Southern Company Gas to net certain assets and liabilities by counterparty. Southern Company Gas also nets across product lines and against cash collateral provided the master netting and cash collateral agreements include such provisions. Southern Company Gas may require counterparties to pledge additional collateral when deemed necessary.

Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas do not anticipate a material adverse effect on the financial statements as a result of counterparty nonperformance.

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Acquisitions and Dispositions

6 Months Ended

Jun. 30, 2018

Business Combinations [Abstract]

ACQUISITIONS AND DISPOSITIONS

ACQUISITIONS AND DISPOSITIONS

Southern Company's Sale of Gulf Power

On May 20, 2018, Southern Company entered into a stock purchase agreement (Gulf Power SPA) with NextEra Energy and its wholly-owned subsidiary 700 Universe, LLC, which provides for the sale of all of the capital stock of Gulf Power for an aggregate cash purchase price of $5.75 billion (less the amount of indebtedness assumed at closing, which is currently estimated at approximately $1.4 billion), subject to (i) customary adjustments for indebtedness and working capital and (ii) reduction by the amount (if any) by which Gulf Power fails to meet a specified capital expenditure target.

The Gulf Power SPA contains customary representations, warranties, and covenants of Southern Company, 700 Universe, LLC, and NextEra Energy. These covenants include, among others, an obligation of Southern Company to cause Gulf Power to operate its business in the ordinary course until the sale is consummated and an obligation for each of the parties to use reasonable best efforts to obtain the governmental and regulatory approvals described below.

The completion of the sale is subject to the satisfaction or waiver of certain closing conditions, including, among others, (i) the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act (HSR Act), (ii) approval by the FERC and the Federal Communications Commission, (iii) the entry into certain ancillary agreements, including transmission-related agreements and a transition services agreement, among the parties and their affiliates, and (iv) other customary closing conditions.

The Gulf Power SPA may be terminated by either Southern Company or 700 Universe, LLC under certain circumstances, including if the sale is not consummated by June 28, 2019 (subject to extension to December 31, 2019, if all of the conditions to closing, other than the conditions related to obtaining regulatory approvals, have been satisfied). The Gulf Power SPA further provides that, upon the termination thereof, (i) under certain specified circumstances, 700 Universe, LLC will be required to pay Southern Company a termination fee of $100 million or $200 million (such amount depending on the specific circumstances of such termination) and (ii) upon certain other specified circumstances Southern Company will be required to pay 700 Universe, LLC a termination fee of $100 million.

The sale of Gulf Power is expected to occur in the first half of 2019. The assets and liabilities of Gulf Power are classified as assets held for sale and liabilities held for sale on Southern Company's balance sheet as of June 30, 2018. See "Assets Held for Sale" below for additional information. The ultimate outcome of this matter cannot be determined at this time.

Southern Power

See Note 11 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.

Acquisitions During the Six Months Ended June 30, 2018

During the six months ended June 30, 2018, one of Southern Power's wholly-owned subsidiaries acquired and completed construction of the Gaskell West 1 solar facility. Acquisition-related costs were expensed as incurred and were not material.

Project Facility	Resource	Seller; Acquisition Date	Approximate Nameplate Capacity (MW)	Location	Southern Power Percentage Ownership		Actual COD	PPA Contract Period
Gaskell West 1	Solar	Recurrent Energy Development Holdings, LLC January 26, 2018	20	Kern County, CA	100% of Class B	(*)	March 2018	20 years

(*) Southern Power owns 100% of the class B membership interests under a tax equity partnership agreement.

The Gaskell West 1 facility did not have operating revenues or activities prior to completion of construction and the assets being placed in service during March 2018.

Construction Projects Completed and in Progress

During the six months ended June 30, 2018, Southern Power started or continued construction of the projects set forth in the table below. Total aggregate construction costs, excluding the acquisition costs, are expected to be between $520 million and $590 million for the Cactus Flats, Mankato, and Wild Horse Mountain facilities. At June 30, 2018, construction costs included in CWIP related to these projects totaled $353 million. The ultimate outcome of these matters cannot be determined at this time.

Project Facility	Resource	Approximate Nameplate Capacity (MW)	Location	Actual/Expected COD	PPA Contract Period
Projects Under Construction as of June 30, 2018
Cactus Flats(a)	Wind	148	Concho County, TX	July 2018	12-15 years
Mankato	Natural Gas	345	Mankato, MN	First half 2019	20 years
Wild Horse Mountain(b)	Wind	100	Pushmataha County, OK	Fourth quarter 2019	20 years

(a) In July 2017, Southern Power purchased 100% of the Cactus Flats facility and commenced construction. Subsequent to June 30, 2018, the facility was placed in service and Southern Power expects to close on a tax equity partnership agreement, which would result in Southern Power owning 100% of the class B membership interests.

(b) In May 2018, Southern Power purchased 100% of the Wild Horse Mountain facility and commenced construction. Southern Power may enter into a tax equity partnership agreement, in which case it would then own 100% of the class B membership interests.

Development Projects

During 2017, as part of its renewable development strategy, Southern Power purchased wind turbine equipment from Siemens Gamesa Renewable Energy Inc. and Vestas-American Wind Technology, Inc. to be used for various development and construction projects. Any wind projects reaching commercial operation by 2021 are expected to qualify for 80% PTCs.

During 2016, Southern Power entered into a joint development agreement with Renewable Energy Systems Americas, Inc. to develop and construct wind projects. In addition, in 2016, Southern Power purchased wind turbine equipment from Siemens Wind Power, Inc. and Vestas-American Wind Technology, Inc. to be used for construction of the facilities. Any wind projects reaching commercial operation by 2020 are expected to qualify for 100% PTCs.

In response to the previously disclosed decrease of planned expenditures for plant acquisitions and placeholder growth, Southern Power continues to refine the deployment of wind turbine equipment to projects and the amount of MW capacity to be constructed. While the expectation is that the majority of the equipment will be deployed in a manner to qualify for the 100% and 80% PTCs, Southern Power may consider other strategies, such as selling equipment or interests in projects.

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

Sale of Solar Facility Interests

In May 2018, Southern Power sold a 33% equity interest in SPSH, a newly-formed limited partnership indirectly owning substantially all of Southern Power's solar facilities, to Global Atlantic Financial Group Limited (Global Atlantic) for approximately $1.2 billion, subject to customary working capital adjustments. The proceeds were used to repay $770 million of existing indebtedness, to return capital of $250 million to Southern Company, and for other general corporate purposes, including working capital. Since Southern Power retains control of the limited partnership through its wholly-owned general partner, the sale was recorded as an equity transaction and Southern Power will continue to consolidate the results of SPSH. On the date of the transaction, the noncontrolling interest was increased by $511 million to reflect 33% of the carrying value of the partnership. This difference, partially offset by the tax impact and other related transaction charges, also resulted in a $407 million decrease to Southern Power's common stockholder's equity.

Sale of Florida Plants

In May 2018, Southern Power entered into an equity interest purchase agreement with NextEra Energy to sell all of its equity interests in the Florida Plants, for an aggregate purchase price of $195 million, subject to customary working capital and timing adjustments.

The sale is subject to certain closing and timing conditions and approvals, including, but not limited to, the expiration or termination of the waiting period under the HSR Act and approval by the FERC. The ultimate purchase price will decrease $110,000 per day for each day after December 31, 2018 through the closing of the transaction. Conversely, the ultimate purchase price will increase $110,000 per day for each day the closing occurs prior to December 31, 2018. The transaction is currently expected to occur in the first half of 2019. As a result of this pending transaction, Southern Power recorded an asset impairment charge of approximately $119 million ($89 million after tax) in the second quarter 2018. The assets and liabilities of the Florida Plants are classified as assets held for sale and liabilities held for sale on Southern Company's and Southern Power's balance sheets as of June 30, 2018. See "Assets Held for Sale" below for additional information. The ultimate outcome of this matter cannot be determined at this time.

Assets Subject to Lien

Under the terms of the PPA and the expansion PPA for the Mankato project, approximately $475 million of assets, primarily related to property, plant, and equipment, are subject to lien at June 30, 2018.

Southern Company Gas

Sale of Pivotal Home Solutions

On June 4, 2018, Southern Company Gas completed the stock sale of Pivotal Home Solutions to American Water Enterprises LLC for a total cash purchase price of $358 million and an additional $6 million for working capital. This disposition resulted in a net loss of $76 million, which included $40 million of income tax expense. In contemplation of the transaction, a goodwill impairment charge of $42 million was recorded during the first quarter 2018. The after-tax loss included income tax expense on goodwill not deductible for tax purposes and for which a deferred tax liability had not been recorded previously. Additionally, this disposition is subject to a final working capital adjustment that may impact the cash proceeds from disposition, but not the loss recorded. Southern Company Gas and American Water Enterprises LLC entered into a transition services agreement whereby Southern Company Gas will provide certain administrative and operational services through no later than February 3, 2019.

Sale of Elizabethtown Gas and Elkton Gas

On July 1, 2018, a Southern Company Gas subsidiary, Pivotal Utility Holdings, completed the sales of the assets of two of its natural gas distribution utilities, Elizabethtown Gas and Elkton Gas, to South Jersey Industries, Inc. for a total cash purchase price of $1.7 billion and an additional $40 million for working capital. This disposition resulted in an estimated pre-tax gain of approximately $235 million and an after-tax gain of approximately $12 million, which will be recorded in the third quarter 2018. The after-tax gain included income tax expense on goodwill not deductible for tax purposes and for which a deferred tax liability had not been recorded previously. Additionally, this disposition is subject to a final working capital adjustment that may impact the cash proceeds from disposition, but not the gain that will be recorded in the third quarter 2018. Southern Company Gas and South Jersey Industries, Inc. entered into transition services agreements whereby Southern Company Gas will provide certain administrative and operational services through no later than January 31, 2020. The assets and liabilities of Elizabethtown Gas and Elkton Gas are classified as assets held for sale and liabilities held for sale on Southern Company's and Southern Company Gas' balance sheets at June 30, 2018. See "Assets Held for Sale" below for additional information.

Sale of Florida City Gas

On July 29, 2018, Southern Company Gas and its wholly-owned direct subsidiary, NUI Corporation, completed the stock sale of Pivotal Utility Holdings, which primarily consisted of Florida City Gas, to NextEra Energyfor a total cash purchase price of$530 million (less $3 million of indebtedness assumed at closing for customer deposits) and an additional $60 million for cash and other working capital. This disposition resulted in an estimated pre-tax gain of approximately $126 million and an after-tax gain of approximately $4 million, which will be recorded in the third quarter 2018. The after-tax gain included income tax expense on goodwill not deductible for tax purposes and for which a deferred tax liability had not been recorded previously. Additionally, this disposition is subject to a final working capital adjustment that may impact the cash proceeds from disposition, but not the gain that will be recorded in the third quarter 2018. Southern Company Gas and NextEra Energy entered into a transition services agreement whereby Southern Company Gas will provide certain administrative and operational services through no later than July 29, 2020. The assets and liabilities of Florida City Gas are classified as assets held for sale and liabilities held for sale on Southern Company's and Southern Company Gas' balance sheets at June 30, 2018. See "Assets Held for Sale" below for additional information.

Assets Held for Sale

As discussed above, Southern Company, Southern Power, and Southern Company Gas each have assets and liabilities held for sale on their balance sheets at June 30, 2018. Assets and liabilities held for sale have been classified separately on each company's balance sheet at the lower of carrying value or fair value less costs to sell at the time the criteria for held-for-sale classification were met. For assets and liabilities held for sale recorded at fair value on a nonrecurring basis, the fair value of assets held for sale is based primarily on unobservable inputs (Level 3), which includes the agreed upon sales prices in executed sales agreements.

Upon classification as held for sale in May 2018, Southern Power ceased recognizing depreciation on the Florida Plants' property, plant, and equipment to be sold. Since the depreciation of the assets to be sold in the Gulf Power transaction continues to be reflected in customer rates and will be reflected in the carryover basis of the assets when sold, Southern Company will continue to record depreciation on those assets through the date the transaction closes. Likewise, since the depreciation of the assets sold in the Elizabethtown Gas, Elkton Gas, and Florida City Gas transactions continued to be reflected in customer rates and was reflected in the carryover basis of the assets when sold, Southern Company Gas continued to record depreciation on those assets through the respective date that each transaction closed.

The following table provides each company's major classes of assets and liabilities classified as held for sale at June 30, 2018:

	Southern Company		Southern Power		Southern Company Gas
	(in millions)
Assets Held for Sale:
Current assets	$	487	$	17	$	81
Total property, plant, and equipment	5,462		168		1,408
Goodwill and other intangible assets	668		—		668
Other non-current assets	705		15		141
Total Assets Held for Sale	$	7,322	$	200	$	2,298
Liabilities Held for Sale:
Current liabilities	$	354	$	2	$	61
Long-term debt	1,285		—		—
Accumulated deferred income taxes	566		—		26
Other non-current liabilities	1,334		—		325
Total Liabilities Held for Sale	$	3,539	$	2	$	412

Southern Company, Southern Power, and Southern Company Gas each concluded that the sale of these assets, both individually and combined, did not represent a strategic shift in operations that has, or is expected to have, a major effect on its operations and financial results; therefore, none of these assets held for sale have been classified as discontinued operations for any of the periods presented.

Gulf Power and the Florida Plants represent individually significant components of Southern Company and Southern Power, respectively; therefore, pre-tax profit for these components for the three and six months ended June 30, 2018 and 2017 is presented below:

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2018		2017		2018		2017
	(in millions)				(in millions)
Earnings before income taxes:
Gulf Power	$	31	$	61	$	87	$	95
Southern Power's Florida Plants(*)	$	14	$	11	$	24	$	20

(*) Excludes any allocation of interest from Southern Power's corporate debt.

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Variable Interest Entity and Equity Method Investments

6 Months Ended

Jun. 30, 2018

Regulated Operations [Abstract]

VARIABLE INTEREST ENTITY AND EQUITY METHOD INVESTMENTS

VARIABLE INTEREST ENTITY AND EQUITY METHOD INVESTMENTS

Southern Power

In May 2018, Southern Power sold a 33% equity interest in SPSH to Global Atlantic. See Note (J) under "Southern Power" for additional information. A wholly-owned subsidiary of Southern Power is the general partner and holds a 1% ownership interest in SPSH and another wholly-owned subsidiary of Southern Power owns the remaining 66% ownership in SPSH. SPSH is a variable interest entity (VIE) because the arrangement is structured as a limited partnership and the 33% limited partner does not have substantive kick-out rights against the general partner. Southern Power previously consolidated SPSH and will continue to do so as the primary beneficiary of the VIE because it controls the most significant activities of the partnership, including operating and maintaining its assets.

At June 30, 2018, SPSH had total assets of $6.5 billion, total liabilities of $0.1 billion, and noncontrolling interests related to other partners' interests of $1.2 billion. Cash distributions from SPSH are allocated 67% to Southern Power and 33% to Global Atlantic in accordance with their membership interests and the limited partnership agreement.

Transfers and sales of the assets in the VIE are subject to limited partner consent and the liabilities do not have recourse to the general credit of Southern Power. Liabilities consist of customary working capital items and do not include any long-term debt.

Southern Company Gas

See Note 4 to the financial statements of Southern Company Gas in Item 8 of the Form 10-K for additional information.

Equity Method Investments

The carrying amounts of Southern Company Gas' equity method investments as of June 30, 2018 and December 31, 2017 and related income from those investments for the three and six-month periods ended June 30, 2018 and June 30, 2017 were as follows:

Investment Balance	June 30, 2018		December 31, 2017
	(in millions)
SNG	$	1,258	$	1,262
Atlantic Coast Pipeline	56		41
PennEast Pipeline	67		57
Triton	42		42
Pivotal JAX LNG, LLC	52		44
Horizon Pipeline	31		30
Other	1		1
Total	$	1,507	$	1,477

Earnings from Equity Method Investments	Three Months Ended June 30, 2018		Three Months Ended June 30, 2017		Six Months Ended June 30, 2018		Six Months Ended June 30, 2017
	(in millions)
SNG	$	27	$	24	$	66	$	58
PennEast Pipeline	1		1		2		4
Atlantic Coast Pipeline	1		2		3		3
Triton	1		2		2		2
Horizon Pipeline	1		—		1		1
Total	$	31	$	29	$	74	$	68

Southern Natural Gas

Selected financial information of SNG for the three and six months ended June 30, 2018 and June 30, 2017 is as follows:

Income Statement Information	Three Months Ended June 30, 2018		Three Months Ended June 30, 2017		Six Months Ended June 30, 2018		Six Months Ended June 30, 2017
	(in millions)
Revenues	$	146	$	143	$	306	$	298
Operating income	$	60	$	63	$	159	$	147
Net income	$	54	$	48	$	132	$	114

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Segment and Related Information

6 Months Ended

Jun. 30, 2018

Segment Reporting [Abstract]

SEGMENT AND RELATED INFORMATION

SEGMENT AND RELATED INFORMATION

Southern Company

The primary businesses of the Southern Company system are electricity sales by the traditional electric operating companies and Southern Power and the distribution of natural gas by Southern Company Gas. 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 develops, constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through its natural gas distribution utilities in four states and is involved in several other complementary businesses including gas marketing services, wholesale gas services, and gas midstream operations. Through June 30, 2018, Southern Company Gas had seven natural gas distribution utilities in seven states. Subsequent to June 30, 2018, Southern Company Gas completed sales of three of its natural gas distribution utilities. See Note (J) under "Southern Company Gas" for additional information.

Southern Company's reportable business segments are the sale of electricity by the four traditional electric operating companies, the sale of electricity in the competitive wholesale market by Southern Power, and the sale of natural gas and other complementary products and services by Southern Company Gas. Revenues from sales by Southern Power to the traditional electric operating companies were $109 million and $192 million for the three and six months ended June 30, 2018, respectively, and $90 million and $190 million for the three and six months ended June 30, 2017, respectively. Revenues from sales of natural gas from Southern Company Gas to the traditional electric operating companies were $8 million for both the three and six months ended June 30, 2018 and $10 million for both the three and six months ended June 30, 2017. Revenues from sales of natural gas from Southern Company Gas to Southern Power were $22 million and $58 million for the three and six months ended June 30, 2018, respectively, and $33 million and $56 million for the three and six months ended June 30, 2017, respectively. The "All Other" column includes the Southern Company parent entity, which does not allocate operating expenses to business segments. Also, this category includes segments below the quantitative threshold for separate disclosure. These segments include providing energy technologies and services to electric utilities and large industrial, commercial, institutional, and municipal customers; 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, 2018 and 2017 was as follows:

	Electric Utilities
	Traditional Electric Operating Companies			Southern Power		Eliminations			Total			Southern Company Gas			All Other			Eliminations			Consolidated
	(in millions)
Three Months Ended June 30, 2018:
Operating revenues	$	4,124		$	555	$	(114	)	$	4,565		$	730		$	381		$	(49	)	$	5,627
Segment net income (loss)(a)(b)(c)	(48		)	22		—			(26		)	(31		)	(100		)	3			(154		)
Six Months Ended June 30, 2018:
Operating revenues	$	8,104		$	1,064	$	(220	)	$	8,948		$	2,369		$	782		$	(100	)	$	11,999
Segment net income (loss)(a)(b)(c)(d)	563			143		—			706			248			(174		)	4			784
At June 30, 2018:
Goodwill	$	—		$	2	$	—		$	2		$	5,015		$	298		$	—		$	5,315
Total assets	73,634			15,428		(313		)	88,749			22,112			3,707			(1,791		)	112,777
Three Months Ended June 30, 2017:
Operating revenues	$	4,157		$	529	$	(101	)	$	4,585		$	716		$	166		$	(37	)	$	5,430
Segment net income (loss)(a)(b)	(1,442		)	82		—			(1,360		)	49			(68		)	(2		)	(1,381		)
Six Months Ended June 30, 2017:
Operating revenues	$	7,943		$	979	$	(206	)	$	8,716		$	2,276		$	289		$	(79	)	$	11,202
Segment net income (loss)(a)(b)(e)	(1,010		)	151		—			(859		)	288			(152		)	—			(723		)
At December 31, 2017:
Goodwill	$	—		$	2	$	—		$	2		$	5,967		$	299		$	—		$	6,268
Total assets	72,204			15,206		(325		)	87,085			22,987			2,552			(1,619		)	111,005

(a) Attributable to Southern Company.

(b) Segment net income (loss) for the traditional electric operating companies includes pre-tax charges for estimated losses on plants under construction of $1.1 billion ($0.8 billion after tax) and $3.0 billion ($2.1 billion after tax) for the three months ended June 30, 2018 and 2017, respectively, and $1.1 billion ($0.8 billion after tax) and $3.1 billion ($2.2 billion after tax) for the six months ended June 30, 2018 and 2017, respectively. See Note 3 to the financial statements of Southern Company under "Kemper County Energy Facility" in Item 8 of the Form 10-K and Note (B) under "Nuclear Construction" and "Kemper County Energy Facility" for additional information.

(c) Segment net income (loss) for Southern Power includes a pre-tax impairment charge of $119 million ($89 million after tax) for the three and six months ended June 30, 2018 related to the pending sale of Southern Power's Florida Plants. See Note (J) under "Southern Power – Sale of Florida Plants" for additional information.

(d) Segment net income (loss) for Southern Company Gas includes a goodwill impairment charge of $42 million for the six months ended June 30, 2018 related to the sale of Pivotal Home Solutions. See Note (J) under "Southern Company Gas – Sale of Pivotal Home Solutions" for additional information.

(e) Segment net income (loss) for the traditional electric operating companies includes a pre-tax charge for the write-down of Gulf Power's ownership of Plant Scherer Unit 3 of $33 million ($20 million after tax) for the six months ended June 30, 2017. See Note 3 to the financial statements of Southern Company under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" in Item 8 of the Form 10-K for additional information.

Products and Services

	Electric Utilities' Revenues
Period	Retail		Wholesale		Other		Total
	(in millions)
Three Months Ended June 30, 2018	$	3,740	$	611	$	214	$	4,565
Three Months Ended June 30, 2017	3,777		618		190		4,585
Six Months Ended June 30, 2018	$	7,308	$	1,230	$	410	$	8,948
Six Months Ended June 30, 2017	7,171		1,149		396		8,716

	Southern Company Gas' Revenues
Period	Gas Distribution Operations		Gas Marketing Services		Other			Total
	(in millions)
Three Months Ended June 30, 2018	$	638	$	89	$	3		$	730
Three Months Ended June 30, 2017	557		166		(7		)	716
Six Months Ended June 30, 2018	$	1,838	$	359	$	172		$	2,369
Six Months Ended June 30, 2017	1,689		454		133			2,276

Southern Company Gas

Southern Company Gas manages its business through four reportable segments – gas distribution operations, gas marketing services, wholesale gas services, and gas midstream operations. The non-reportable segments are combined and presented as all other.

Gas distribution operations is the largest component of Southern Company Gas' business and includes natural gas local distribution utilities that construct, manage, and maintain intrastate natural gas pipelines and gas distribution facilities in seven states. Subsequent to June 30, 2018, Southern Company Gas sold three of its natural gas distribution utilities, Elizabethtown Gas, Elkton Gas, and Florida City Gas. See Note (J) under "Southern Company Gas" for additional information.

Gas marketing services includes natural gas marketing to end-use customers primarily in Georgia and Illinois. On June 4, 2018, Southern Company Gas sold Pivotal Home Solutions. See Note (J) under "Southern Company Gas" for additional information.

Wholesale gas services provides natural gas asset management and/or related logistics services for each of Southern Company Gas' utilities except Nicor Gas as well as for non-affiliated companies. Additionally, wholesale gas services engages in natural gas storage and gas pipeline arbitrage and related activities.

Gas midstream operations primarily consists of Southern Company Gas' pipeline investments, with storage and fuel operations also aggregated into this segment.

The all other column includes segments below the quantitative threshold for separate disclosure, including the subsidiaries that fall below the quantitative threshold for separate disclosure.

Business segment financial data for the three and six months ended June 30, 2018 and 2017 was as follows:

	Gas Distribution Operations(a)		Gas Marketing Services(b)(c)			Wholesale Gas Services(d)			Gas Midstream Operations		Total			All Other			Eliminations			Consolidated
	(in millions)
Three Months Ended June 30, 2018:
Operating revenues	$	643	$	89		$	(16	)	$	18	$	734		$	1		$	(5	)	$	730
Segment net income	68		(76		)	(21		)	14		(15		)	(16		)	—			(31		)
Six Months Ended June 30, 2018:
Operating revenues	1,856		359			150			40		2,405			2			(38		)	2,369
Segment net income	216		(63		)	83			38		274			(26		)	—			248
Total assets at June 30, 2018:	18,654		1,610			818			2,269		23,351			11,544			(12,783		)	22,112
Three Months Ended June 30, 2017:
Operating revenues	$	603	$	166		$	(12	)	$	12	$	769		$	3		$	(56	)	$	716
Segment net income	54		4			(17		)	9		50			(1		)	—			49
Six Months Ended June 30, 2017:
Operating revenues	1,783		454			119			37		2,393			5			(122		)	2,276
Segment net income	171		35			51			25		282			6			—			288
Total assets at December 31, 2017:	19,358		2,147			1,096			2,241		24,842			12,184			(14,039		)	22,987

(a) Operating revenues for the three gas distribution operations dispositions were $70 million and $66 million for the three months ended June 30, 2018 and 2017, respectively, and $237 million and $224 million for the six months ended June 30, 2018 and 2017, respectively. See Note (J) under "Southern Company Gas" for additional information.

(b) Operating revenues for the gas marketing services disposition were $24 million and $32 million for the three months ended June 30, 2018 and 2017, respectively, and $55 million and $63 million for the six months ended June 30, 2018 and 2017, respectively. See Note (J) under "Southern Company Gas" for additional information.

(c) Segment net income for gas marketing services includes a loss on disposition of $36 million for the three and six months ended June 30, 2018 and a goodwill impairment charge of $42 million for the six months ended June 30, 2018 recorded in contemplation of the sale of Pivotal Home Solutions. See Note (J) under "Southern Company Gas" for additional information.

(d) The revenues for wholesale gas services are netted with costs associated with its energy and risk management activities. A reconciliation of operating revenues and intercompany revenues is shown in the following table.

	Third Party Gross Revenues		Intercompany Revenues		Total Gross Revenues		Less Gross Gas Costs		Operating Revenues
	(in millions)
Three Months Ended June 30, 2018	$	1,336	$	102	$	1,438	$	1,454	$	(16	)
Three Months Ended June 30, 2017	1,531		123		1,654		1,666		(12		)
Six Months Ended June 30, 2018	$	3,274	$	269	$	3,543	$	3,393	$	150
Six Months Ended June 30, 2017	3,370		259		3,629		3,510		119

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Introduction (Policies)

6 Months Ended

Jun. 30, 2018

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of Accounting

The condensed quarterly financial statements of each registrant included herein have been prepared by such registrant, without audit, pursuant to the rules and regulations of the SEC. The Condensed Balance Sheets as of December 31, 2017 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, 2018 and 2017. Certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations, although each registrant believes that the disclosures regarding such registrant are adequate to make the information presented not misleading. Disclosures which would substantially duplicate the disclosures in the Form 10-K and details which have not changed significantly in amount or composition since the filing of the Form 10-K are generally omitted from this Quarterly Report on Form 10-Q unless specifically required by GAAP. Therefore, these Condensed Financial Statements should be read in conjunction with the financial statements and the notes thereto included in the Form 10-K. Due to the seasonal variations in the demand for energy, operating results for the periods presented are not necessarily indicative of the operating results to be expected for the full year.

Reclassification

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

Recently Adopted Accounting Standards

Recently Adopted Accounting Standards

See Note 1 to the financial statements of the registrants under "Recently Issued Accounting Standards" in Item 8 of the Form 10-K for additional information.

Revenue

In 2014, the FASB issued ASC 606, Revenue from Contracts with Customers (ASC 606), replacing the existing accounting standard and industry-specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. ASC 606 became effective on January 1, 2018 and the registrants adopted it using the modified retrospective method applied to open contracts and only to the version of the contracts in effect as of January 1, 2018. In accordance with the modified retrospective method, the registrants' previously issued financial statements have not been restated to comply with ASC 606 and the registrants did not have a cumulative-effect adjustment to retained earnings. The adoption of ASC 606 had no significant impact on the timing of revenue recognition compared to previously reported results; however, it requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers, which are included in Note (C).

ASC 606 provided additional clarity on financial statement presentation that resulted in reclassifications into other revenues and other operations and maintenance from other income/(expense), net at Alabama Power and Georgia Power related to certain unregulated sales of products and services. In addition, contract assets related to Southern Company's unregulated distributed generation business have been reclassified from unbilled revenue in accordance with the guidance in ASC 606. These reclassifications did not affect the timing or amount of revenues recognized or cash flows. ASC 606 also provided additional guidance on over-time revenue recognition, resulting in a change in the timing of revenue recognized from guaranteed and fixed billing arrangements at Southern Company Gas. The changes in natural gas revenues recognized in the second quarter and year-to-date 2018 relate primarily to the seasonal nature of natural gas usage.

The net impact of accounting for revenue under ASC 606 decreased Southern Company's consolidated net income by $5 million for the three months ended June 30, 2018 and increased Southern Company's consolidated net income by $5 million for the six months ended June 30, 2018.

The specific impacts of applying ASC 606 to revenues from contracts with customers on the financial statements of Southern Company, Alabama Power, Georgia Power, and Southern Company Gas compared to previously recognized guidance is shown below.

	For the Three Months Ended June 30, 2018									For the Six Months Ended June 30, 2018
Condensed Statements of Income	As Reported			Balances Without Adoption of ASC 606			Effect of Change			As Reported			Balances Without Adoption of ASC 606			Effect of Change
	(in millions)									(in millions)
Southern Company
Natural gas revenues	$	706		$	713		$	(7	)	$	2,314		$	2,307		$	7
Other revenues	395			393			2			808			805			3
Other operations and maintenance	1,559			1,546			13			3,008			2,985			23
Operating income	63			81			(18		)	1,439			1,452			(13		)
Other income (expense), net	78			67			11			138			118			20
Earnings (loss) before income taxes	(266		)	(259		)	(7		)	784			777			7
Income taxes (benefit)	(139		)	(137		)	(2		)	(25		)	(27		)	2
Consolidated net income (loss)	(127		)	(122		)	(5		)	809			804			5
Consolidated net income (loss) attributable to Southern Company	(154		)	(149		)	(5		)	784			779			5
Alabama Power
Other revenues	$	69		$	60		$	9		$	131		$	114		$	17
Other operations and maintenance	402			391			11			788			767			21
Operating income	380			382			(2		)	752			756			(4		)
Other income (expense), net	12			10			2			15			11			4
Georgia Power
Other revenues	$	120		$	97		$	23		$	227		$	189		$	38
Other operations and maintenance	457			437			20			863			828			35
Operating income (loss)	(472		)	(475		)	3			41			38			3
Other income (expense), net	35			38			(3		)	73			76			(3		)
Southern Company Gas
Natural gas revenues	$	710		$	717		$	(7	)	$	2,341		$	2,334		$	7
Operating income	49			56			(7		)	436			429			7
Earnings before income taxes	24			31			(7		)	407			400			7
Income taxes	55			57			(2		)	159			157			2
Net income (loss)	(31		)	(26		)	(5		)	248			243			5

	For the Six Months Ended June 30, 2018
Condensed Statements of Cash Flows	As Reported			Balances Without Adoption of ASC 606			Effect of Change
	(in millions)
Southern Company
Consolidated net income	$	809		$	804		$	5
Changes in certain current assets and liabilities:
Receivables	94			99			(5		)
Other current assets	(40		)	(45		)	5
Accrued taxes	213			215			(2		)
Other current liabilities	125			118			7
Georgia Power
Changes in certain current assets and liabilities:
Receivables	$	(103	)	$	(75	)	$	(28	)
Other current assets	25			(3		)	28
Southern Company Gas
Net income	$	248		$	243		$	5
Changes in certain current assets and liabilities:
Accrued taxes	38			40			(2		)
Other current liabilities	24			17			7

	At June 30, 2018
Condensed Balance Sheets	As Reported			Balances Without Adoption of ASC 606			Effect of Change
	(in millions)
Southern Company
Unbilled revenues	$	769		$	824		$	(55	)
Other accounts and notes receivable	621			622			(1		)
Other current assets	172			116			56
Accrued taxes	544			542			2
Other current liabilities	808			815			(7		)
Retained earnings	8,494			8,489			5
Southern Company Gas
Accrued income taxes	$	86		$	84		$	2
Other current liabilities	143			150			(7		)
Accumulated deficit	(202		)	(207		)	5

Other

In 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (ASU 2016-18). ASU 2016-18 eliminates the need to reflect transfers between cash and restricted cash in operating, investing, and financing activities in the statements of cash flows. In addition, the net change in cash and cash equivalents during the period includes amounts generally described as restricted cash or restricted cash equivalents. The registrants adopted ASU 2016-18 effective January 1, 2018 with no material impact on their financial statements. Southern Company, Southern Power, and Southern Company Gas retrospectively applied ASU 2016-18 effective January 1, 2018 and have restated prior periods in the statements of cash flows by immaterial amounts. The change in restricted cash in the statements of cash flows was previously disclosed in operating activities for Southern Company and Southern Company Gas and in investing activities for Southern Company and Southern Power. See "Restricted Cash" herein for additional information.

In March 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in the statements of income outside of income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. The registrants adopted ASU 2017-07 effective January 1, 2018 with no material impact on their financial statements. ASU 2017-07 has been applied retrospectively for the presentation of the service cost component and the other components of net periodic benefit costs in the statements of income for Southern Company, the traditional electric operating companies, and Southern Company Gas. Since Southern Power did not participate in the qualified pension and postretirement benefit plans until December 2017, no retrospective presentation of Southern Power's net periodic benefits costs is required. The requirement to limit capitalization to the service cost component of net periodic benefit costs has been applied on a prospective basis from the date of adoption for all registrants. The presentation changes resulted in a decrease in operating income and an increase in other income for the three and six months ended June 30, 2018 and 2017 for Southern Company, the traditional electric operating companies, and Southern Company Gas.

In August 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12). ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The registrants adopted ASU 2017-12 effective January 1, 2018 with no material impact on their financial statements. See Note (I) for disclosures required by ASU 2017-12.

On February 14, 2018, the FASB issued ASU No. 2018-02, Income Statement – Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income (ASU 2018-02) to address the application of ASC 740, Income Taxes (ASC 740) to certain provisions of the Tax Reform Legislation. ASU 2018-02 specifically addresses the ASC 740 requirement that the effect of a change in tax laws or rates on deferred tax assets and liabilities be included in income from continuing operations, even when the tax effects were initially recognized directly in OCI at the previous rate, which strands the income tax rate differential in accumulated OCI. The amendments in ASU 2018-02 allow a reclassification from accumulated OCI to retained earnings for stranded tax effects resulting from the Tax Reform Legislation. The registrants adopted ASU 2018-02 effective January 1, 2018 with no material impact on their financial statements.

Goodwill and Other Intangible Assets

Goodwill is not amortized but is subject to an annual impairment test during the fourth quarter of each year or more frequently if impairment indicators arise.

Restricted Cash

Restricted Cash

The registrants adopted ASU 2016-18 as of January 1, 2018. See "Recently Adopted Accounting Standards – Other" herein for additional information.

At December 31, 2017, Southern Power had restricted cash primarily related to certain acquisitions and construction projects. At both June 30, 2018 and December 31, 2017, Southern Company Gas had restricted cash held as collateral for worker's compensation, life insurance, and long-term disability insurance.

Natural Gas For Sale

Natural Gas for Sale

Southern Company Gas' natural gas distribution utilities, with the exception of Nicor Gas, carry natural gas inventory on a WACOG basis.

Nicor Gas' natural gas inventory is carried at cost on a LIFO basis. Inventory decrements occurring during the year that are restored prior to year end are charged to cost of natural gas at the estimated annual replacement cost. Inventory decrements that are not restored prior to year end are charged to cost of natural gas at the actual LIFO cost of the inventory layers liquidated. Southern Company Gas' inventory decrement at June 30, 2018 is expected to be restored prior to year end. The cost of natural gas, including inventory costs, is recovered from customers under a purchased gas recovery mechanism adjusted for differences between actual costs and amounts billed; therefore, LIFO liquidations have no impact on Southern Company's or Southern Company Gas' net income.

Natural gas inventories for Southern Company Gas' non-utility businesses are carried at the lower of weighted average cost or current market price, with cost determined on a WACOG basis. For any declines in market prices below the WACOG considered to be other than temporary, an adjustment is recorded to reduce the value of natural gas inventories to market value.

Hypothetical Liquidation at Book Value

Hypothetical Liquidation at Book Value

Southern Power has consolidated renewable generation projects that are partially funded by a third-party tax equity investor. The related contractual provisions represent profit-sharing arrangements because the allocations of cash distributions and tax benefits are not based on fixed ownership percentages. Therefore, the noncontrolling interest is accounted for under a balance sheet approach utilizing the hypothetical liquidation at book value (HLBV) method. The HLBV method calculates each partner's share of income based on the change in net equity the partner can legally claim in a hypothetical liquidation at the end of the period compared to the beginning of the period.

Valuation Methodologies

Valuation Methodologies

The energy-related derivatives primarily consist of exchange-traded and 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 reflects 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 reflects 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 data and valuations of similar instruments. See Note (I) 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.

Southern Power has contingent payment obligations related to certain acquisitions whereby Southern Power is primarily obligated to make generation-based payments to the seller, which commenced at the commercial operation date of the respective facility and continue through 2026. The obligation is categorized as Level 3 under Fair Value Measurements as the fair value is determined using significant unobservable inputs for the forecasted facility generation in MW-hours, as well as other inputs such as a fixed dollar amount per MW-hour, and a discount rate. The fair value of contingent consideration reflects the net present value of expected payments and any periodic change arising from forecasted generation is expected to be immaterial.

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

Earnings per Share

Earnings per Share

For Southern Company, the only difference in computing basic and diluted earnings per share is attributable to awards outstanding under stock-based compensation plans. See Note 8 to the financial statements of Southern Company in Item 8 of the Form 10-K for information on stock-based compensation plans. The effect of stock-based compensation plans was determined using the treasury stock method.

Derivatives

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 derivatives' fair value gains or losses are recorded in OCI and are reclassified into earnings at the same time and presented on the same income statement line item as the earnings effect of the hedged transactions. 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 on the same income statement line item. 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.

Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas are exposed to market risks, including commodity price risk, interest rate risk, weather risk, and occasionally foreign currency exchange rate risk. To manage the volatility attributable to these exposures, each company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to each company's policies in areas such as counterparty exposure and risk management practices. Southern Company Gas' wholesale gas operations use various contracts in its commercial activities that generally meet the definition of derivatives. For the traditional electric operating companies, Southern Power, and Southern Company Gas' other businesses, 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 net basis. See Note (D) 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.

The registrants adopted ASU 2017-12 as of January 1, 2018. See Note (A) under "Recently Adopted Accounting Standards – Other" for additional information.

Energy-Related Derivatives

Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas enter into energy-related derivatives to hedge exposures to electricity, natural gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the traditional electric operating companies and the natural gas distribution utilities have limited exposure to market volatility in energy-related commodity prices. Each of the traditional electric operating companies and certain of the natural gas distribution utilities of Southern Company Gas manage fuel-hedging programs, implemented per the guidelines of their respective state PSCs or other applicable state regulatory agencies, through the use of financial derivative contracts, which is expected to continue to mitigate price volatility. The Florida PSC approved a moratorium on Gulf Power's fuel-hedging program until January 1, 2021. The moratorium does not have an impact on the recovery of existing hedges entered into under the previously-approved hedging program. The traditional electric operating companies (with respect to wholesale generating capacity) and Southern Power have limited exposure to market volatility in energy-related commodity prices 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 capacity is used to sell electricity. Southern Company Gas retains exposure to price changes that can, in a volatile energy market, be material and can adversely affect its results of operations.

Southern Company Gas also enters into weather derivative contracts as economic hedges of operating margins in the event of warmer-than-normal weather. Exchange-traded options are carried at fair value, with changes reflected in operating revenues. Non-exchange-traded options are accounted for using the intrinsic value method. Changes in the intrinsic value for non-exchange-traded contracts are reflected in operating revenues.

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' and the natural gas distribution utilities' 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 and in the same income statement line item as the earnings effect of the hedged transactions.

• 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 and natural gas industries. When an energy-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed and the contract price is recognized in the respective line item representing the actual price of the underlying goods being delivered.

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Introduction (Tables)

6 Months Ended

Jun. 30, 2018

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Schedule of New Accounting Pronouncements and Changes in Accounting Principles

The specific impacts of applying ASC 606 to revenues from contracts with customers on the financial statements of Southern Company, Alabama Power, Georgia Power, and Southern Company Gas compared to previously recognized guidance is shown below.

	For the Three Months Ended June 30, 2018									For the Six Months Ended June 30, 2018
Condensed Statements of Income	As Reported			Balances Without Adoption of ASC 606			Effect of Change			As Reported			Balances Without Adoption of ASC 606			Effect of Change
	(in millions)									(in millions)
Southern Company
Natural gas revenues	$	706		$	713		$	(7	)	$	2,314		$	2,307		$	7
Other revenues	395			393			2			808			805			3
Other operations and maintenance	1,559			1,546			13			3,008			2,985			23
Operating income	63			81			(18		)	1,439			1,452			(13		)
Other income (expense), net	78			67			11			138			118			20
Earnings (loss) before income taxes	(266		)	(259		)	(7		)	784			777			7
Income taxes (benefit)	(139		)	(137		)	(2		)	(25		)	(27		)	2
Consolidated net income (loss)	(127		)	(122		)	(5		)	809			804			5
Consolidated net income (loss) attributable to Southern Company	(154		)	(149		)	(5		)	784			779			5
Alabama Power
Other revenues	$	69		$	60		$	9		$	131		$	114		$	17
Other operations and maintenance	402			391			11			788			767			21
Operating income	380			382			(2		)	752			756			(4		)
Other income (expense), net	12			10			2			15			11			4
Georgia Power
Other revenues	$	120		$	97		$	23		$	227		$	189		$	38
Other operations and maintenance	457			437			20			863			828			35
Operating income (loss)	(472		)	(475		)	3			41			38			3
Other income (expense), net	35			38			(3		)	73			76			(3		)
Southern Company Gas
Natural gas revenues	$	710		$	717		$	(7	)	$	2,341		$	2,334		$	7
Operating income	49			56			(7		)	436			429			7
Earnings before income taxes	24			31			(7		)	407			400			7
Income taxes	55			57			(2		)	159			157			2
Net income (loss)	(31		)	(26		)	(5		)	248			243			5

	For the Six Months Ended June 30, 2018
Condensed Statements of Cash Flows	As Reported			Balances Without Adoption of ASC 606			Effect of Change
	(in millions)
Southern Company
Consolidated net income	$	809		$	804		$	5
Changes in certain current assets and liabilities:
Receivables	94			99			(5		)
Other current assets	(40		)	(45		)	5
Accrued taxes	213			215			(2		)
Other current liabilities	125			118			7
Georgia Power
Changes in certain current assets and liabilities:
Receivables	$	(103	)	$	(75	)	$	(28	)
Other current assets	25			(3		)	28
Southern Company Gas
Net income	$	248		$	243		$	5
Changes in certain current assets and liabilities:
Accrued taxes	38			40			(2		)
Other current liabilities	24			17			7

	At June 30, 2018
Condensed Balance Sheets	As Reported			Balances Without Adoption of ASC 606			Effect of Change
	(in millions)
Southern Company
Unbilled revenues	$	769		$	824		$	(55	)
Other accounts and notes receivable	621			622			(1		)
Other current assets	172			116			56
Accrued taxes	544			542			2
Other current liabilities	808			815			(7		)
Retained earnings	8,494			8,489			5
Southern Company Gas
Accrued income taxes	$	86		$	84		$	2
Other current liabilities	143			150			(7		)
Accumulated deficit	(202		)	(207		)	5

Schedule of Change in Asset Retirement Obligation

As of June 30, 2018, details of the AROs, including those related to the CCR Rule, included in the condensed balance sheets of Southern Company, Alabama Power, and Mississippi Power were as follows:

	Southern Company			Alabama Power			Mississippi Power
	(in millions)
Balance at December 31, 2017	$	4,824		$	1,709		$	174
Liabilities incurred	1			—			—
Liabilities settled	(97		)	(19		)	(15		)
Accretion	95			41			2
Cash flow revisions	1,493			1,451			15
Reclassification to held for sale	(148		)	—			—
Balance at June 30, 2018	$	6,168		$	3,182		$	176

Estimated Cost Of Decommissioning

In June 2018, Alabama Power completed an updated decommissioning cost site study for Plant Farley. The estimated costs of decommissioning based on the 2018 site study are as follows:

Decommissioning periods:
Beginning year	2037
Completion year	2076
	(in millions)
Site study costs:
Radiated structures	$	1,621
Non-radiated structures	99
Total site study costs	$	1,720

Schedule of Goodwill

The following table presents year-to-date changes in goodwill balances for Southern Company and Southern Company Gas:

	Goodwill
	Southern Company				Southern Company Gas
					Gas Distribution Operations			Gas Marketing Services			Total
	(in millions)
Balance at December 31, 2017	$	6,268			$	4,702		$	1,265		$	5,967
Impairment(a)	(42		)		—			(42		)	(42		)
Sale of Pivotal Home Solutions(a)	(242		)		—			(242		)	(242		)
Reclassification to held for sale(b)	(668		)		(668		)	—			(668		)
Balance at June 30, 2018	$	5,315		(c)	$	4,034		$	981		$	5,015

(a) On April 11, 2018, Southern Company Gas entered into a stock purchase agreement for the sale of Pivotal Home Solutions. In contemplation of the transaction, a goodwill impairment charge of $42 million was recorded in the first quarter 2018. On June 4, 2018, Southern Company Gas and Pivotal Home Solutions completed this transaction. See Note (J) under "Southern Company Gas" for additional information.

(b) Reflects goodwill associated with Elizabethtown Gas, Elkton Gas, and Florida City Gas, which were sold subsequent to June 30, 2018. See Note (J) under "Southern Company Gas" and "Assets Held for Sale" for additional information.

(c) Total does not add due to rounding.

Schedule of Goodwill and Other Intangible Assets

Other intangible assets were as follows:

	At June 30, 2018							At December 31, 2017
	Gross Carrying Amount		Accumulated Amortization			Other Intangible Assets, Net		Gross Carrying Amount		Accumulated Amortization			Other Intangible Assets, Net
	(in millions)							(in millions)
Southern Company
Other intangible assets subject to amortization:
Customer relationships(*)	$	223	$	(79	)	$	144	$	288	$	(83	)	$	205
Trade names(*)	70		(17		)	53		159		(17		)	142
Storage and transportation contracts	64		(44		)	20		64		(34		)	30
PPA fair value adjustments	456		(60		)	396		456		(47		)	409
Other	19		(5		)	14		17		(5		)	12
Total other intangible assets subject to amortization	$	832	$	(205	)	$	627	$	984	$	(186	)	$	798
Other intangible assets not subject to amortization:
Federal Communications Commission licenses	75		—			75		75		—			75
Total other intangible assets	$	907	$	(205	)	$	702	$	1,059	$	(186	)	$	873
Southern Power
Other intangible assets subject to amortization:
PPA fair value adjustments	$	456	$	(60	)	$	396	$	456	$	(47	)	$	409
Southern Company Gas
Other intangible assets subject to amortization:
Gas marketing services(*)
Customer relationships	$	156	$	(71	)	$	85	$	221	$	(77	)	$	144
Trade names	26		(6		)	20		115		(9		)	106
Wholesale gas services
Storage and transportation contracts	64		(44		)	20		64		(34		)	30
Total other intangible assets subject to amortization	$	246	$	(121	)	$	125	$	400	$	(120	)	$	280

(*) Balances as of June 30, 2018 reflect Southern Company Gas' sale of Pivotal Home Solutions. See Note (J) under "Southern Company Gas – Sale of Pivotal Home Solutions" for additional information.

Finite-lived Intangible Assets Amortization Expense

Amortization associated with other intangible assets was as follows:

	Three Months Ended		Six Months Ended
	June 30, 2018
	(in millions)
Southern Company	$	23	$	50
Southern Power	$	6	$	13
Southern Company Gas	$	14	$	31

Schedule of Cash and Cash Equivalents

The following tables provide a reconciliation of cash, cash equivalents, and restricted cash reported within the condensed balance sheets that total to the amounts shown in the condensed statements of cash flows for the registrants that had restricted cash at June 30, 2018 and/or December 31, 2017:

	Southern Company		Southern Company Gas
	(in millions)
At June 30, 2018
Cash and cash equivalents	$	1,980	$	69
Cash and cash equivalents classified as assets held for sale	31		—
Restricted cash:
Other accounts and notes receivable	6		6
Total cash, cash equivalents, and restricted cash	$	2,017	$	75

	Southern Company		Southern Power		Southern Company Gas
	(in millions)
At December 31, 2017
Cash and cash equivalents	$	2,130	$	129	$	73
Restricted cash:
Other accounts and notes receivable	5		—		5
Deferred charges and other assets	12		11		—
Total cash, cash equivalents, and restricted cash	$	2,147	$	140	$	78

Restrictions on Cash and Cash Equivalents

The following tables provide a reconciliation of cash, cash equivalents, and restricted cash reported within the condensed balance sheets that total to the amounts shown in the condensed statements of cash flows for the registrants that had restricted cash at June 30, 2018 and/or December 31, 2017:

	Southern Company		Southern Company Gas
	(in millions)
At June 30, 2018
Cash and cash equivalents	$	1,980	$	69
Cash and cash equivalents classified as assets held for sale	31		—
Restricted cash:
Other accounts and notes receivable	6		6
Total cash, cash equivalents, and restricted cash	$	2,017	$	75

	Southern Company		Southern Power		Southern Company Gas
	(in millions)
At December 31, 2017
Cash and cash equivalents	$	2,130	$	129	$	73
Restricted cash:
Other accounts and notes receivable	5		—		5
Deferred charges and other assets	12		11		—
Total cash, cash equivalents, and restricted cash	$	2,147	$	140	$	78

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Contingencies and Regulatory Matters - (Tables)

6 Months Ended

Jun. 30, 2018

Commitments and Contingencies Disclosure [Abstract]

Cost Recovery Clauses

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

Regulatory Clause	Balance Sheet Line Item	June 30, 2018		December 31, 2017
		(in millions)
Rate CNP Compliance	Deferred under recovered regulatory clause revenues	$	30	$	17
Rate CNP PPA	Deferred under recovered regulatory clause revenues	11		12
Retail Energy Cost Recovery	Deferred under recovered regulatory clause revenues	80		25
	Under recovered regulatory clause revenues	28		—
Natural Disaster Reserve	Other regulatory liabilities, deferred	30		38

Regulatory clause recovery balances included in the balance sheets are as follows:

Regulatory Clause	Balance Sheet Line Item	June 30, 2018		December 31, 2017
		(in millions)
Fuel Cost Recovery	Under recovered regulatory clause revenues	$	—	$	22
Fuel Cost Recovery	Other regulatory liabilities, current	5		—
Purchased Power Capacity Recovery	Under recovered regulatory clause revenues	2		2
Environmental Cost Recovery(*)	Under recovered regulatory clause revenues	1		2
Energy Conservation Cost Recovery	Other regulatory liabilities, current	1		—

(*) At June 30, 2018 and December 31, 2017, the under recovered balance included in the balance sheets represents the current portion of the regulatory assets associated with projected environmental expenditures of approximately $11 million and $13 million, respectively, partially offset by the over recovered environmental cost recovery balance of approximately $10 million and $11 million, respectively.

Revised Cost and Schedule

Georgia Power's approximate proportionate share of the remaining estimated capital cost to complete Plant Vogtle Units 3 and 4 by the expected in-service dates of November 2021 and November 2022, respectively, is as follows:

	(in billions)
Base project capital cost forecast(a)(b)	$	8.0
Construction contingency estimate	0.4
Total project capital cost forecast(a)(b)	8.4
Net investment as of June 30, 2018(b)	(4.0		)
Remaining estimate to complete(a)	$	4.4

(a) Excludes financing costs expected to be capitalized through AFUDC of approximately $350 million.

(b) Net of $1.7 billion received from Toshiba in 2017 under the Guarantee Settlement Agreement and $188 million in Customer Refunds recognized as a regulatory liability in 2017.

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Revenue from Contracts with Customers (Tables)

6 Months Ended

Jun. 30, 2018

Revenue from Contract with Customer [Abstract]

Disaggregation of Revenue

The following tables disaggregate revenue sources for the three and six months ended June 30, 2018:

	For the Three Months Ended June 30, 2018			For the Six Months Ended June 30, 2018
	(in millions)
Southern Company
Operating revenues
Retail electric revenues(a)
Residential	$	1,579		$	3,118
Commercial	1,315			2,557
Industrial	814			1,569
Other	32			64
Natural gas distribution revenues	642			1,865
Alternative revenue programs(b)	(4		)	(27		)
Total retail electric and gas distribution revenues	$	4,378		$	9,146
Wholesale energy revenues(c)(d)	459			928
Wholesale capacity revenues(d)	152			302
Other natural gas revenues(e)	68			476
Other revenues(f)	570			1,147
Total operating revenues	$	5,627		$	11,999

(a) Retail electric revenues include $18 million and $36 million of leases for the three and six months ended June 30, 2018, respectively, and a net increase of $68 million and $101 million for the three and six months ended June 30, 2018, respectively, from certain cost recovery mechanisms that are not accounted for as revenue under ASC 606. See Note 3 to the financial statements of Southern Company under "Regulatory Matters" in Item 8 of the Form 10-K for additional information on cost recovery mechanisms.

(b) See Note 1 to the financial statements of Southern Company under "Revenues" in Item 8 of the Form 10-K for additional information on alternative revenue programs at the natural gas distribution utilities. Alternative revenue program revenues are presented net of any previously recognized program amounts billed to customers during the same accounting period.

(c) Wholesale energy revenues include $61 million and $155 million for the three and six months ended June 30, 2018, respectively, of revenues accounted for as derivatives, primarily related to physical energy sales in the wholesale electricity market. See Note (I) for additional information on energy-related derivative contracts.

(d) Wholesale energy and wholesale capacity revenues include $118 million and $31 million, respectively, for the three months ended June 30, 2018 and $187 million and $61 million, respectively, for the six months ended June 30, 2018 of PPA contracts accounted for as leases.

(e) Other natural gas revenues related to Southern Company Gas' energy and risk management activities are presented net of the related costs of those activities and include gross third-party revenues of $1.3 billion and $3.3 billion for the three and six months ended June 30, 2018, respectively, of which $0.7 billion and $1.8 billion, respectively, relates to contracts that are accounted for as derivatives. See Note (L) under "Southern Company Gas" for additional information on the components of wholesale gas services operating revenues.

(f) Other revenues include $89 million and $183 million for the three and six months ended June 30, 2018, respectively, of revenues not accounted for under ASC 606.

	Alabama Power		Georgia Power		Gulf Power		Mississippi Power
	(in millions)
For the Three Months Ended June 30, 2018
Operating revenues
Retail revenues(a)(b)
Residential	$	557	$	785	$	172	$	65
Commercial	402		749		96		68
Industrial	372		335		31		76
Other	7		20		2		3
Total retail electric revenues	$	1,338	$	1,889	$	301	$	212
Wholesale energy revenues(c)	71		26		21		73
Wholesale capacity revenues	25		13		6		1
Other revenues(b)(d)	69		120		16		11
Total operating revenues	$	1,503	$	2,048	$	344	$	297
For the Six Months Ended June 30, 2018
Operating revenues
Retail revenues(a)(b)
Residential	$	1,127	$	1,529	$	337	$	125
Commercial	774		1,466		188		130
Industrial	710		650		63		146
Other	13		43		3		5
Total retail electric revenues	$	2,624	$	3,688	$	591	$	406
Wholesale energy revenues(c)	172		66		56		167
Wholesale capacity revenues	49		27		12		5
Other revenues(b)(d)	131		227		33		20
Total operating revenues	$	2,976	$	4,008	$	692	$	598

(a) Retail revenues at Alabama Power, Georgia Power, Gulf Power, and Mississippi Power include a net increase or (net reduction) of $78 million, $3 million, $(12) million, and $(1) million, respectively, for the three months ended June 30, 2018 and $125 million, $12 million, $(28) million, and $(8) million, respectively, for the six months ended June 30, 2018 related to certain cost recovery mechanisms that are not accounted for as revenue under ASC 606. See Note 3 to the financial statements of Alabama Power, Georgia Power, Gulf Power, and Mississippi Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information on cost recovery mechanisms.

(b) Retail revenues and other revenues at Georgia Power include $18 million and $33 million, respectively, for the three months ended June 30, 2018 and $36 million and $66 million, respectively, for the six months ended June 30, 2018 of revenues accounted for as leases.

(c) Wholesale energy revenues at Alabama Power and Georgia Power include $4 million and $5 million, respectively, for the three months ended June 30, 2018 and $9 million and $13 million, respectively, for the six months ended June 30, 2018 accounted for as derivatives primarily related to physical energy sales in the wholesale electricity market. See Note (I) for additional information on energy-related derivative contracts.

(d) Other revenues at Alabama Power, Georgia Power, and Gulf Power include $26 million, $26 million, and $2 million, respectively, for the three months ended June 30, 2018 and $52 million, $53 million, and $4 million, respectively, for the six months ended June 30, 2018 of revenues not accounted for under ASC 606.

	For the Three Months Ended June 30, 2018		For the Six Months Ended June 30, 2018
	(in millions)
Southern Power
PPA capacity revenues(a)	$	144	$	282
PPA energy revenues(a)	302		556
Non-PPA revenues(b)	106		221
Other revenues	3		5
Total operating revenues	$	555	$	1,064

(a) PPA capacity revenues and PPA energy revenues include $47 million and $127 million, respectively, for the three months ended June 30, 2018 and $94 million and $203 million, respectively, for the six months ended June 30, 2018 related to PPAs accounted for as leases. See Note 1 to the financial statements of Southern Power under "Revenues" in Item 8 of the Form 10-K for additional information on capacity revenues accounted for as leases.

(b) Non-PPA revenues include $50 million and $129 million for the three and six months ended June 30, 2018, respectively, of revenues from short-term sales related to physical energy sales from uncovered capacity in the wholesale electricity market. See Note 1 to the financial statements of Southern Power under "Revenues" in Item 8 of the Form 10-K and Note (I) for additional information on energy-related derivative contracts.

	For the Three Months Ended June 30, 2018			For the Six Months Ended June 30, 2018
	(in millions)
Southern Company Gas
Operating revenues
Natural gas distribution revenues
Residential	$	273		$	933
Commercial	76			268
Transportation	7			24
Industrial	228			505
Other	58			135
Alternative revenue programs(a)	(4		)	(27		)
Total natural gas distribution revenues	$	638		$	1,838
Gas marketing services(b)	89			359
Wholesale gas services(c)	(15		)	131
Gas midstream operations	18			40
Other revenues	—			1
Total operating revenues	$	730		$	2,369

(a) See Note 1 to the financial statements of Southern Company Gas under "Revenues" in Item 8 of the Form 10-K for additional information on alternative revenue programs at the natural gas distribution utilities. Alternative revenue program revenues are presented net of any previously recognized program amounts billed to customers during the same accounting period.

(b) Gas marketing services includes $4 million for the six months ended June 30, 2018 of revenues not accounted for under ASC 606.

(c) Wholesale gas services revenues are presented net of the related costs associated with its energy trading and risk management activities. Operating revenues, as presented, include gross third-party revenues of $1.3 billion and $3.3 billion for the three and six months ended June 30, 2018, respectively, of which $0.7 billion and $1.8 billion, respectively, relates to contracts that are accounted for as derivatives. See Note (L) under "Southern Company Gas" for additional information on the components of wholesale gas services operating revenues and Note (I) for additional information on energy-related derivative contracts.

Contract with Customer, Asset and Liability

The following table reflects the closing balances of receivables, contract assets, and contract liabilities related to revenues from contracts with customers as of June 30, 2018:

	Receivables		Contract Assets		Contract Liabilities
	(in millions)
Southern Company	$	2,785	$	33	$	36
Alabama Power	603		—		10
Georgia Power	840		9		9
Gulf Power	169		—		1
Mississippi Power	83		—		—
Southern Power	136		—		4
Southern Company Gas	570		—		1

Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction

Revenues from contracts with customers related to these performance obligations remaining at June 30, 2018 are expected to be recognized as follows:

	2018		2019		2020		2021		2022		2023 and Thereafter
	(in millions)
Southern Company(*)	$	263	$	352	$	322	$	322	$	310	$	1,960
Alabama Power	11		22		22		26		23		161
Georgia Power	20		41		38		40		30		113
Gulf Power	11		22		—		—		—		—
Mississippi Power	2		3		3		1		—		—
Southern Power(*)	211		310		283		277		276		1,809

(*) Excludes amounts related to held for sale assets. See Note (J) under "Southern Company's Sale of Gulf Power" and "Southern Power – Sale of Florida Plants" for additional information.

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Fair Value Measurements (Tables)

6 Months Ended

Jun. 30, 2018

Fair Value Disclosures [Abstract]

Assets and Liabilities Measured at Fair Value on a Recurring Basis

As of June 30, 2018, 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, 2018:	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(a)(b)	$	287	$	166	$	—	$	—	$	453
Foreign currency derivatives	—		132		—		—		132
Nuclear decommissioning trusts(c)	798		998		—		33		1,829
Cash equivalents	1,449		—		—		—		1,449
Other investments	9		—		1		—		10
Total	$	2,543	$	1,296	$	1	$	33	$	3,873
Liabilities:
Energy-related derivatives(a)(b)	$	422	$	151	$	—	$	—	$	573
Interest rate derivatives	—		68		—		—		68
Foreign currency derivatives	—		23		—		—		23
Contingent consideration	—		—		22		—		22
Total	$	422	$	242	$	22	$	—	$	686
Alabama Power
Assets:
Energy-related derivatives	$	—	$	8	$	—	$	—	$	8
Nuclear decommissioning trusts:(d)
Domestic equity	440		86		—		—		526
Foreign equity	61		55		—		—		116
U.S. Treasury and government agency securities	—		18		—		—		18
Corporate bonds	28		158		—		—		186
Mortgage and asset backed securities	—		18		—		—		18
Private equity	—		—		—		33		33
Other	7		—		—		—		7
Cash equivalents	495		—		—		—		495
Total	$	1,031	$	343	$	—	$	33	$	1,407
Liabilities:
Energy-related derivatives	$	—	$	9	$	—	$	—	$	9

	Fair Value Measurements Using:
As of June 30, 2018:	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	$	—	$	7	$	—	$	—	$	7
Nuclear decommissioning trusts:(d) (e)
Domestic equity	242		1		—		—		243
Foreign equity	—		135		—		—		135
U.S. Treasury and government agency securities	—		239		—		—		239
Municipal bonds	—		78		—		—		78
Corporate bonds	—		164		—		—		164
Mortgage and asset backed securities	—		41		—		—		41
Other	19		5		—		—		24
Total	$	261	$	670	$	—	$	—	$	931
Liabilities:
Energy-related derivatives	$	—	$	19	$	—	$	—	$	19
Interest rate derivatives	—		6		—		—		6
Total	$	—	$	25	$	—	$	—	$	25
Gulf Power
Assets:
Cash equivalents	$	27	$	—	$	—	$	—	$	27
Liabilities:
Energy-related derivatives	$	—	$	12	$	—	$	—	$	12
Mississippi Power
Assets:
Energy-related derivatives	$	—	$	3	$	—	$	—	$	3
Cash equivalents	205		—		—		—		205
Total	$	205	$	3	$	—	$	—	$	208
Liabilities:
Energy-related derivatives	$	—	$	9	$	—	$	—	$	9

	Fair Value Measurements Using:
As of June 30, 2018:	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	$	—	$	3	$	—	$	—	$	3
Foreign currency derivatives	—		132		—		—		132
Total	$	—	$	135	$	—	$	—	$	135
Liabilities:
Energy-related derivatives	$	—	$	3	$	—	$	—	$	3
Foreign currency derivatives	—		23		—		—		23
Contingent consideration	—		—		22		—		22
Total	$	—	$	26	$	22	$	—	$	48
Southern Company Gas
Assets:
Energy-related derivatives(a)(b)	$	287	$	144	$	—	$	—	$	431
Cash equivalents	1		—		—		—		1
Total	$	288	$	144	$	—	$	—	$	432
Liabilities:
Energy-related derivatives(a)(b)	$	422	$	99	$	—	$	—	$	521

(a) Excludes $3 million associated with premiums and certain weather derivatives accounted for based on intrinsic value rather than fair value.

(b) Excludes cash collateral of $183 million.

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

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

(e) Includes the investment securities pledged to creditors and collateral received and excludes payables related to the securities lending program. As of June 30, 2018, approximately $63 million of the fair market value of Georgia Power's nuclear decommissioning trust funds' securities were on loan to creditors under the funds' managers' securities lending program.

Fair Value Measurements of Investments Calculated at Net Asset Value per Share as Well as the Nature and Risk of Those Investments

As of June 30, 2018, the fair value measurements of private equity investments held in the nuclear decommissioning trusts 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, 2018:	Fair Value		Unfunded Commitments		Redemption Frequency	Redemption Notice Period
	(in millions)
Southern Company	$	33	$	33	Not Applicable	Not Applicable
Alabama Power	$	33	$	33	Not Applicable	Not Applicable

Financial Instruments for Which Carrying Amount Did Not Equal Fair Value

As of June 30, 2018, 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	$	45,806	$	46,481
Alabama Power	8,119		8,435
Georgia Power	10,294		10,499
Gulf Power	1,285		1,311
Mississippi Power	1,779		1,760
Southern Power	5,037		5,094
Southern Company Gas	5,823		5,957

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Stockholders' Equity (Tables)

6 Months Ended

Jun. 30, 2018

Equity [Abstract]

Earnings per Share

Shares used to compute diluted earnings per share were as follows:

	Three Months Ended June 30, 2018	Three Months Ended June 30, 2017	Six Months Ended June 30, 2018	Six Months Ended June 30, 2017
	(in millions)
As reported shares	1,014	998	1,012	996
Effect of stock-based compensation	—	7	5	7
Diluted shares	1,014	1,005	1,017	1,003

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(a)
	(in thousands)			(in millions)
Balance at December 31, 2017	1,008,532	(929	)	$	24,167		$	—		$	1,361		$	25,528
Consolidated net income attributable to Southern Company	—	—		784			—			—			784
Other comprehensive income	—	—		41			—			—			41
Stock issued	6,590	—		222			—			—			222
Stock-based compensation	—	—		48			—			—			48
Cash dividends on common stock	—	—		(1,194		)	—			—			(1,194		)
Contributions from noncontrolling interests	—	—		—			—			31			31
Distributions to noncontrolling interests	—	—		—			—			(42		)	(42		)
Net income attributable to noncontrolling interests	—	—		—			—			17			17
Sale of SPSH noncontrolling interests(b)	—	—		(407		)	—			1,690			1,283
Other	—	(57	)	(25		)	—			(1		)	(26		)
Balance at June 30, 2018	1,015,122	(986	)	$	23,636		$	—		$	3,056		$	26,692
Balance at December 31, 2016	991,213	(819	)	$	24,758		$	609		$	1,245		$	26,612
Consolidated net income attributable to Southern Company	—	—		(723		)	—			—			(723		)
Other comprehensive income (loss)	—	—		(11		)	—			—			(11		)
Stock issued	9,129	—		417			—			—			417
Stock-based compensation	—	—		72			—			—			72
Cash dividends on common stock	—	—		(1,134		)	—			—			(1,134		)
Preference stock redemption	—	—		—			(150		)	—			(150		)
Contributions from noncontrolling interests	—	—		—			—			71			71
Distributions to noncontrolling interests	—	—		—			—			(40		)	(40		)
Net income attributable to noncontrolling interests	—	—		—			—			16			16
Reclassification from redeemable noncontrolling interests	—	—		—			—			114			114
Other	—	(49	)	(7		)	3			1			(3		)
Balance at June 30, 2017	1,000,342	(868	)	$	23,372		$	462		$	1,407		$	25,241

(a) Primarily related to Southern Power Company and excludes redeemable noncontrolling interests. See Note 10 to the financial statements of Southern Power in Item 8 of the Form 10-K for additional information.

(b) See Note (J) under "Southern Power – Sale of Solar Facility Interests" for additional information.

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Financing (Tables)

6 Months Ended

Jun. 30, 2018

Debt Disclosure [Abstract]

Credit Arrangements by Company

The following table outlines the committed credit arrangements by company as of June 30, 2018:

	Expires												Executable Term Loans		Expires Within One Year
Company	2018		2019		2020		2022		Total		Unused		One Year		Term Out		No Term Out
	(in millions)
Southern Company(a)	$	—	$	—	$	—	$	2,000	$	2,000	$	1,999	$	—	$	—	$	—
Alabama Power	2		31		500		800		1,333		1,333		—		—		33
Georgia Power	—		—		—		1,750		1,750		1,736		—		—		—
Gulf Power	20		25		235		—		280		280		45		45		—
Mississippi Power	100		—		—		—		100		100		—		—		100
Southern Power Company(b)	—		—		—		750		750		728		—		—		—
Southern Company Gas(c)	—		—		—		1,900		1,900		1,895		—		—		—
Other	—		30		—		—		30		30		—		—		30
Southern Company Consolidated	$	122	$	86	$	735	$	7,200	$	8,143	$	8,101	$	45	$	45	$	163

(a) Represents the Southern Company parent entity.

(b) Does not include Southern Power's $120 million continuing letter of credit facility for standby letters of credit expiring in 2019, of which $23 million remains unused at June 30, 2018.

(c) Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $1.4 billion of these arrangements. Southern Company Gas' committed credit arrangements also include $500 million for which Nicor Gas is the borrower and which is restricted for working capital needs of Nicor Gas.

Schedule of Long-term Debt Financing Activities

The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first six months of 2018:

Company	Senior Note Issuances		Senior Note Maturities, Redemptions, and Repurchases		Revenue Bond Maturities, Redemptions, and Repurchases		Other Long-Term Debt Redemptions and Maturities(*)
	(in millions)
Alabama Power	$	500	$	—	$	—	$	—
Georgia Power	—		1,000		398		104
Mississippi Power	600		—		—		900
Southern Power	—		350		—		420
Southern Company Gas	—		—		200		—
Other	—		—		—		7
Southern Company Consolidated	$	1,100	$	1,350	$	598	$	1,431

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

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Retirement Benefits (Tables)

6 Months Ended

Jun. 30, 2018

Retirement Benefits [Abstract]

Pension Plans and Postretirement Plans

Components of the net periodic benefit costs for the three and six months ended June 30, 2018 and 2017 are presented in the following tables.

Three Months Ended June 30, 2018	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power			Southern Power			Southern Company Gas
	(in millions)
Pension Plans
Service cost	$	89		$	20		$	21		$	4		$	4		$	2		$	8
Interest cost	116			25			35			5			5			2			9
Expected return on plan assets	(235		)	(53		)	(74		)	(10		)	(10		)	(2		)	(17		)
Amortization:
Prior service costs	1			1			1			—			—			—			—
Regulatory asset	—			—			—			—			—			—			4
Net (gain)/loss	54			13			17			3			2			—			3
Net periodic pension cost (income)	$	25		$	6		$	—		$	2		$	1		$	2		$	7
Postretirement Benefits
Service cost	$	6		$	2		$	1		$	1		$	1		$	—		$	—
Interest cost	18			4			7			—			1			—			3
Expected return on plan assets	(17		)	(7		)	(7		)	(1		)	(1		)	—			(2		)
Amortization:
Prior service costs	1			1			1			—			—			—			—
Regulatory asset	—			—			—			—			—			—			2
Net (gain)/loss	4			1			2			—			—			—			—
Net periodic postretirement benefit cost	$	12		$	1		$	4		$	—		$	1		$	—		$	3

Six Months Ended June 30, 2018	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power			Southern Power			Southern Company Gas
	(in millions)
Pension Plans
Service cost	$	179		$	39		$	43		$	8		$	8		$	4		$	16
Interest cost	232			50			70			10			10			3			19
Expected return on plan assets	(471		)	(104		)	(148		)	(20		)	(20		)	(5		)	(35		)
Amortization:
Prior service costs	2			1			1			—			—			—			(1		)
Regulatory asset	—			—			—			—			—			—			7
Net (gain)/loss	107			27			34			5			5			1			6
Net periodic pension cost (income)	$	49		$	13		$	—		$	3		$	3		$	3		$	12
Postretirement Benefits
Service cost	$	12		$	3		$	3		$	1		$	1		$	—		$	1
Interest cost	37			8			14			1			2			—			5
Expected return on plan assets	(34		)	(13		)	(13		)	(1		)	(1		)	—			(4		)
Amortization:
Regulatory asset	3			2			1			—			—			—			3
Net (gain)/loss	7			1			4			—			—			—			—
Net periodic postretirement benefit cost	$	25		$	1		$	9		$	1		$	2		$	—		$	5

Three Months Ended June 30, 2017(*)	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power			Southern Company Gas
	(in millions)
Pension Plans
Service cost	$	74		$	16		$	18		$	4		$	3		$	5
Interest cost	113			24			35			5			5			10
Expected return on plan assets	(225		)	(49		)	(70		)	(9		)	(10		)	(17		)
Amortization:
Prior service costs	3			—			1			—			1			(1		)
Net (gain)/loss	41			11			14			1			2			5
Net periodic pension cost (income)	$	6		$	2		$	(2	)	$	1		$	1		$	2
Postretirement Benefits
Service cost	$	6		$	2		$	1		$	1		$	1		$	—
Interest cost	20			4			8			—			1			2
Expected return on plan assets	(17		)	(8		)	(6		)	(1		)	(1		)	(1		)
Amortization:
Prior service costs	1			1			1			—			—			—
Net (gain)/loss	5			1			1			—			—			1
Net periodic postretirement benefit cost	$	15		$	—		$	5		$	—		$	1		$	2

(*) Excludes Southern Power since Southern Power did not participate in the qualified pension and postretirement benefit plans until December 2017.

Six Months Ended June 30, 2017(*)	Southern Company			Alabama Power			Georgia Power			Gulf Power			Mississippi Power			Southern Company Gas
	(in millions)
Pension Plans
Service cost	$	147		$	32		$	37		$	7		$	7		$	11
Interest cost	227			48			69			10			10			20
Expected return on plan assets	(449		)	(98		)	(141		)	(19		)	(20		)	(35		)
Amortization:
Prior service costs	6			1			2			—			1			(1		)
Net (gain)/loss	81			21			28			3			4			10
Net periodic pension cost (income)	$	12		$	4		$	(5	)	$	1		$	2		$	5
Postretirement Benefits
Service cost	$	12		$	3		$	3		$	1		$	1		$	1
Interest cost	40			9			15			1			2			5
Expected return on plan assets	(33		)	(14		)	(12		)	(1		)	(1		)	(3		)
Amortization:
Prior service costs	3			2			1			—			—			(1		)
Net (gain)/loss	7			1			3			—			—			2
Net periodic postretirement benefit cost	$	29		$	1		$	10		$	1		$	2		$	4

(*) Excludes Southern Power since Southern Power did not participate in the qualified pension and postretirement benefit plans until December 2017.

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Derivatives (Tables)

6 Months Ended

Jun. 30, 2018

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Energy-Related Derivatives

At June 30, 2018, 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(*)	701	2022	2029
Alabama Power	82	2022	—
Georgia Power	174	2022	—
Gulf Power	13	2020	—
Mississippi Power	66	2022	—
Southern Power	14	2020	—
Southern Company Gas(*)	352	2020	2029

(*) Southern Company's and Southern Company Gas' derivative instruments include both long and short natural gas positions. A long position is a contract to purchase natural gas and a short position is a contract to sell natural gas. Southern Company Gas' volume represents the net of long natural gas positions of 3.9 billion mmBtu and short natural gas positions of 3.6 billion mmBtu as of June 30, 2018, which is also included in Southern Company's total volume.

Schedule of Interest Rate Derivatives

At June 30, 2018, 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, 2018
	(in millions)					(in millions)
Fair Value Hedges of Existing Debt
Southern Company(*)	$	300	2.75%	3-month LIBOR + 0.92%	June 2020	$	(6	)
Southern Company(*)	1,500		2.35%	1-month LIBOR + 0.87%	July 2021	(57		)
Georgia Power	500		1.95%	3-month LIBOR + 0.76%	December 2018	(3		)
Georgia Power	200		4.25%	3-month LIBOR + 2.46%	December 2019	(3		)
Southern Company Consolidated	$	2,500				$	(69	)

(*) Represents the Southern Company parent entity.

Schedule of Foreign Currency Derivatives

At June 30, 2018, 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, 2018
	(in millions)			(in millions)				(in millions)
Cash Flow Hedges of Existing Debt
Southern Power	$	677	2.95%	€	600	1.00%	June 2022	$	54
Southern Power	564		3.78%	500		1.85%	June 2026	55
Total	$	1,241		€	1,100			$	109

Fair Value of Energy-Related Derivatives and Interest Rate Derivatives

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

	As of June 30, 2018						As of December 31, 2017
Derivative Category and Balance Sheet Location	Assets			Liabilities			Assets			Liabilities
	(in millions)						(in millions)
Southern Company
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	16		$	12		$	10		$	43
Other deferred charges and assets/Other deferred credits and liabilities	5			27			7			24
Assets held for sale, current/Liabilities held for sale, current	—			8			—			—
Assets held for sale/Liabilities held for sale	—			4			—			—
Total derivatives designated as hedging instruments for regulatory purposes	$	21		$	51		$	17		$	67
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Other current assets/Other current liabilities	$	2		$	3		$	3		$	14
Other deferred charges and assets/Other deferred credits and liabilities	1			1			—			—
Interest rate derivatives:
Other current assets/Other current liabilities	—			15			1			4
Other deferred charges and assets/Other deferred credits and liabilities	—			53			—			34
Foreign currency derivatives:
Other current assets/Other current liabilities	—			23			—			23
Other deferred charges and assets/Other deferred credits and liabilities	132			—			129			—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	135		$	95		$	133		$	75
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets/Other current liabilities	$	239		$	272		$	380		$	437
Other deferred charges and assets/Other deferred credits and liabilities	189			246			170			215
Total derivatives not designated as hedging instruments	$	428		$	518		$	550		$	652
Gross amounts recognized	$	584		$	664		$	700		$	794
Gross amounts offset(a)	$	(306	)	$	(489	)	$	(405	)	$	(598	)
Net amounts recognized in the Balance Sheets(b)	$	278		$	175		$	295		$	196

	As of June 30, 2018						As of December 31, 2017
Derivative Category and Balance Sheet Location	Assets			Liabilities			Assets			Liabilities
	(in millions)						(in millions)
Alabama Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	6		$	3		$	2		$	6
Other deferred charges and assets/Other deferred credits and liabilities	2			6			2			4
Total derivatives designated as hedging instruments for regulatory purposes	$	8		$	9		$	4		$	10
Gross amounts recognized	$	8		$	9		$	4		$	10
Gross amounts offset	$	(4	)	$	(4	)	$	(4	)	$	(4	)
Net amounts recognized in the Balance Sheets	$	4		$	5		$	—		$	6
Georgia Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	5		$	5		$	2		$	9
Other deferred charges and assets/Other deferred credits and liabilities	2			14			4			10
Total derivatives designated as hedging instruments for regulatory purposes	$	7		$	19		$	6		$	19
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current assets/Other current liabilities	$	—		$	5		$	—		$	4
Other deferred charges and assets/Other deferred credits and liabilities	—			1			—			1
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	—		$	6		$	—		$	5
Gross amounts recognized	$	7		$	25		$	6		$	24
Gross amounts offset	$	(7	)	$	(7	)	$	(6	)	$	(6	)
Net amounts recognized in the Balance Sheets	$	—		$	18		$	—		$	18
Gulf Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	—		$	8		$	—		$	14
Other deferred charges and assets/Other deferred credits and liabilities	—			4			—			7
Total derivatives designated as hedging instruments for regulatory purposes	$	—		$	12		$	—		$	21
Gross amounts recognized	$	—		$	12		$	—		$	21
Gross amounts offset	$	—		$	—		$	—		$	—
Net amounts recognized in the Balance Sheets	$	—		$	12		$	—		$	21

	As of June 30, 2018						As of December 31, 2017
Derivative Category and Balance Sheet Location	Assets			Liabilities			Assets			Liabilities
	(in millions)						(in millions)
Mississippi Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	2		$	3		$	1		$	6
Other deferred charges and assets/Other deferred credits and liabilities	1			6			1			3
Total derivatives designated as hedging instruments for regulatory purposes	$	3		$	9		$	2		$	9
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current assets/Other current liabilities	$	—		$	—		$	1		$	—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	—		$	—		$	1		$	—
Gross amounts recognized	$	3		$	9		$	3		$	9
Gross amounts offset	$	(2	)	$	(2	)	$	(2	)	$	(2	)
Net amounts recognized in the Balance Sheets	$	1		$	7		$	1		$	7
Southern Power
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Other current assets/Other current liabilities	$	2		$	2		$	3		$	11
Other deferred charges and assets/Other deferred credits and liabilities	1			1			—			—
Foreign currency derivatives:
Other current assets/Other current liabilities	—			23			—			23
Other deferred charges and assets/Other deferred credits and liabilities	132			—			129			—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	135		$	26		$	132		$	34
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets/Other current liabilities	$	—		$	—		$	—		$	2
Gross amounts recognized	$	135		$	26		$	132		$	36
Gross amounts offset	$	(2	)	$	(2	)	$	(3	)	$	(3	)
Net amounts recognized in the Balance Sheets	$	133		$	24		$	129		$	33

	As of June 30, 2018						As of December 31, 2017
Derivative Category and Balance Sheet Location	Assets			Liabilities			Assets			Liabilities
	(in millions)						(in millions)
Southern Company Gas
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Assets from risk management activities/Liabilities from risk management activities-current	$	3		$	1		$	5		$	8
Other deferred charges and assets/Other deferred credits and liabilities	—			1			—			—
Total derivatives designated as hedging instruments for regulatory purposes	$	3		$	2		$	5		$	8
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Assets from risk management activities/Liabilities from risk management activities-current	$	—		$	1		$	—		$	3
Derivatives not designated as hedging instruments
Energy-related derivatives:
Assets from risk management activities/Liabilities from risk management activities-current	$	239		$	272		$	379		$	434
Other deferred charges and assets/Other deferred credits and liabilities	189			246			170			215
Total derivatives not designated as hedging instruments	$	428		$	518		$	549		$	649
Gross amounts of recognized	$	431		$	521		$	554		$	660
Gross amounts offset(a)	$	(291	)	$	(474	)	$	(390	)	$	(583	)
Net amounts recognized in the Balance Sheets(b)	$	140		$	47		$	164		$	77

(a) Gross amounts offset include cash collateral held on deposit in broker margin accounts of $183 million and $193 million as of June 30, 2018 and December 31, 2017, respectively.

(b) Net amounts of derivative instruments outstanding exclude premium and intrinsic value associated with weather derivatives of $3 million and $11 million as of June 30, 2018 and December 31, 2017, respectively.

Pre-tax Effects of Unrealized Derivative Gains (Losses) Arising from Energy-Related Derivative Instruments

At June 30, 2018 and December 31, 2017, 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 in the Balance Sheet at June 30, 2018
Derivative Category and Balance Sheet Location	Southern Company(*)			Alabama Power			Georgia Power			Gulf Power			Mississippi Power			Southern Company Gas(*)
	(in millions)
Energy-related derivatives:
Other regulatory assets, current	$	(4	)	$	(1	)	$	(1	)	$	(8	)	$	(1	)	$	(1	)
Other regulatory assets, deferred	(20		)	(4		)	(11		)	(4		)	(5		)	—
Assets held for sale, current	(8		)	—			—			—			—			—
Assets held for sale	(4		)	—			—			—			—			—
Other regulatory liabilities, current	8			4			—			—			—			4
Total energy-related derivative gains (losses)	$	(28	)	$	(1	)	$	(12	)	$	(12	)	$	(6	)	$	3

(*) Fair value gains and losses recorded in regulatory assets and liabilities include cash collateral held on deposit in broker margin accounts of $2 million at June 30, 2018.

Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at December 31, 2017
Derivative Category and Balance Sheet Location	Southern Company(*)			Alabama Power			Georgia Power			Gulf Power			Mississippi Power			Southern Company Gas(*)
	(in millions)
Energy-related derivatives:
Other regulatory assets, current	$	(34	)	$	(4	)	$	(7	)	$	(14	)	$	(5	)	$	(4	)
Other regulatory assets, deferred	(18		)	(3		)	(6		)	(7		)	(2		)	—
Other regulatory liabilities, current	7			—			—			—			—			7
Other regulatory liabilities, deferred	1			1			—			—			—			—
Total energy-related derivative gains (losses)	$	(44	)	$	(6	)	$	(13	)	$	(21	)	$	(7	)	$	3

(*) Fair value gains and losses recorded in regulatory assets and liabilities include cash collateral held on deposit in broker margin accounts of $6 million at December 31, 2017.

Pre-tax Effects of Interest Rate Derivatives, Designated as Cash Flow Hedging Instruments

For the three and six months ended June 30, 2018 and 2017, the pre-tax effects of cash flow hedge accounting on accumulated OCI were as follows:

Gain (Loss) Recognized in OCI on Derivative	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2018			2017			2018			2017
	(in millions)						(in millions)
Southern Company
Energy-related derivatives	$	—		$	(9	)	$	12		$	(20	)
Interest rate derivatives	—			(1		)	(2		)	(1		)
Foreign currency derivatives	(73		)	71			(21		)	67
Total	$	(73	)	$	61		$	(11	)	$	46
Southern Power
Energy-related derivatives	$	(1	)	$	(7	)	$	10		$	(15	)
Foreign currency derivatives	(73		)	71			(21		)	67
Total	$	(74	)	$	64		$	(11	)	$	52
Southern Company Gas
Energy-related derivatives	$	1		$	(2	)	$	2		$	(4	)

Schedule of Cash Flow Hedging Instruments, Statements of Financial Performance and Financial Position, Location

For the three and six months ended June 30, 2018 and 2017, the pre-tax effects of cash flow and fair value hedge accounting on income were as follows:

Location and Amount of Gain (Loss) Recognized in Income on Cash Flow and Fair Value Hedging Relationships	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2018			2017			2018			2017
	(in millions)						(in millions)
Southern Company
Depreciation and amortization	$	783		$	754		$	1,552		$	1,469
Gain (loss) on cash flow hedges(a)
Energy-related derivatives	1			(2		)	2			(6		)
Interest expense, net of amounts capitalized	(470		)	(424		)	(928		)	(840		)
Gain (loss) on cash flow hedges(a)
Interest rate derivatives	(6		)	(5		)	(11		)	(10		)
Foreign currency derivatives	(7		)	(5		)	(12		)	(12		)
Gain (loss) on fair value hedges(b)
Interest rate derivatives	(7		)	7			(31		)	(1		)
Other income (expense), net	78			52			138			98
Gain (loss) on cash flow hedges(a)(c)
Foreign currency derivatives	(73		)	79			(37		)	96
Cost of natural gas	228			232			949			951
Gain (loss) on cash flow hedges(a)
Energy-related derivatives	—			—			(2		)	—
Alabama Power
Interest expense, net of amounts capitalized	$	(80	)	$	(77	)	$	(158	)	$	(153	)
Gain (loss) on cash flow hedges(a)
Interest rate derivatives	(1		)	(2		)	(3		)	(3		)
Georgia Power
Interest expense, net of amounts capitalized	$	(102	)	$	(104	)	$	(208	)	$	(205	)
Gain (loss) on cash flow hedges(a)
Interest rate derivatives	(2		)	(1		)	(3		)	(3		)
Gain (loss) on fair value hedges(b)
Interest rate derivatives	2			—			(1		)	(1		)
Mississippi Power
Interest expense, net of amounts capitalized	$	(21	)	$	(17	)	$	(39	)	$	(37	)
Gain (loss) on cash flow hedges(a)
Interest rate derivatives	(1		)	—			(1		)	(1		)

Location and Amount of Gain (Loss) Recognized in Income on Cash Flow and Fair Value Hedging Relationships	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2018			2017			2018			2017
	(in millions)						(in millions)
Southern Power
Depreciation and amortization	$	125		$	129		$	240		$	247
Gain (loss) on cash flow hedges(a)
Energy-related derivatives	1			(2		)	2			(6		)
Interest expense, net of amounts capitalized	(46		)	(48		)	(93		)	(97		)
Gain (loss) on cash flow hedges(a)
Foreign currency derivatives	(7		)	(5		)	(12		)	(12		)
Other income (expense), net	2			2			5			(2		)
Gain (loss) on cash flow hedges(a)(c)
Foreign currency derivatives	(73		)	79			(37		)	96
Southern Company Gas
Cost of natural gas	$	228		$	232		$	949		$	951
Gain (loss) on cash flow hedges(a)
Energy-related derivatives	—			—			(2		)	—

(a) Amounts reflect gains or losses on cash flow hedges that were reclassified from accumulated OCI into income.

(b) For fair value hedges presented above, generally changes in the fair value of the derivative contracts are equal to changes in the fair value of the underlying debt and have no material impact on income.

(c) The reclassification from accumulated OCI into other income (expense), net completely offsets currency gains and losses arising from changes in the U.S. currency exchange rates used to record the euro-denominated notes.

Schedule of Fair Value Hedging Instruments, Statements of Financial Performance and Financial Position, Location

As of June 30, 2018 and December 31, 2017, the following amounts were recorded on the balance sheets related to cumulative basis adjustments for fair value hedges:

	Carrying Amount of the Hedged Item						Cumulative Amount of Fair Value Hedging Adjustment included in Carrying Amount of the Hedged Item
Balance Sheet Location of Hedged Items	As of June 30, 2018			As of December 31, 2017			As of June 30, 2018		As of December 31, 2017
	(in millions)						(in millions)
Southern Company
Securities due within one year	$	(497	)	$	(746	)	$	3	$	3
Long-term Debt	(2,528		)	(2,553		)	63		35
Georgia Power
Securities due within one year	$	(497	)	$	(746	)	$	3	$	3
Long-term Debt	(497		)	(498		)	3		1

Pre-tax Effect of Interest Rate and Energy Related Derivatives

For the three and six months ended June 30, 2018 and 2017, the pre-tax effects of energy-related derivatives not designated as hedging instruments on the statements of income were as follows:

		Gain (Loss)
		Three Months Ended June 30,						Six Months Ended June 30,
Derivatives in Non-Designated Hedging Relationships	Statements of Income Location	2018			2017			2018			2017
		(in millions)						(in millions)
Southern Company
Energy-related derivatives:	Natural gas revenues(*)	$	(28	)	$	16		$	(43	)	$	65
	Cost of natural gas	2			(2		)	4			(4		)
Total derivatives in non-designated hedging relationships		$	(26	)	$	14		$	(39	)	$	61
Southern Company Gas
Energy-related derivatives:	Natural gas revenues(*)	$	(28	)	$	16		$	(43	)	$	65
	Cost of natural gas	2			(2		)	4			(4		)
Total derivatives in non-designated hedging relationships		$	(26	)	$	14		$	(39	)	$	61

(*) Excludes gains (losses) recorded in natural gas revenues associated with weather derivatives of $15 million for the six months ended June 30, 2017 and immaterial amounts for all other periods presented.

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Acquisitions and Dispositions (Tables)

6 Months Ended

Jun. 30, 2018

Business Combinations [Abstract]

Schedule of Business Acquisitions

Project Facility	Resource	Seller; Acquisition Date	Approximate Nameplate Capacity (MW)	Location	Southern Power Percentage Ownership		Actual COD	PPA Contract Period
Gaskell West 1	Solar	Recurrent Energy Development Holdings, LLC January 26, 2018	20	Kern County, CA	100% of Class B	(*)	March 2018	20 years

(*) Southern Power owns 100% of the class B membership interests under a tax equity partnership agreement.

Schedule of Construction Projects

Project Facility	Resource	Approximate Nameplate Capacity (MW)	Location	Actual/Expected COD	PPA Contract Period
Projects Under Construction as of June 30, 2018
Cactus Flats(a)	Wind	148	Concho County, TX	July 2018	12-15 years
Mankato	Natural Gas	345	Mankato, MN	First half 2019	20 years
Wild Horse Mountain(b)	Wind	100	Pushmataha County, OK	Fourth quarter 2019	20 years

(a) In July 2017, Southern Power purchased 100% of the Cactus Flats facility and commenced construction. Subsequent to June 30, 2018, the facility was placed in service and Southern Power expects to close on a tax equity partnership agreement, which would result in Southern Power owning 100% of the class B membership interests.

(b) In May 2018, Southern Power purchased 100% of the Wild Horse Mountain facility and commenced construction. Southern Power may enter into a tax equity partnership agreement, in which case it would then own 100% of the class B membership interests.

Disposal Groups, Including Discontinued Operations

The following table provides each company's major classes of assets and liabilities classified as held for sale at June 30, 2018:

	Southern Company		Southern Power		Southern Company Gas
	(in millions)
Assets Held for Sale:
Current assets	$	487	$	17	$	81
Total property, plant, and equipment	5,462		168		1,408
Goodwill and other intangible assets	668		—		668
Other non-current assets	705		15		141
Total Assets Held for Sale	$	7,322	$	200	$	2,298
Liabilities Held for Sale:
Current liabilities	$	354	$	2	$	61
Long-term debt	1,285		—		—
Accumulated deferred income taxes	566		—		26
Other non-current liabilities	1,334		—		325
Total Liabilities Held for Sale	$	3,539	$	2	$	412

Gulf Power and the Florida Plants represent individually significant components of Southern Company and Southern Power, respectively; therefore, pre-tax profit for these components for the three and six months ended June 30, 2018 and 2017 is presented below:

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2018		2017		2018		2017
	(in millions)				(in millions)
Earnings before income taxes:
Gulf Power	$	31	$	61	$	87	$	95
Southern Power's Florida Plants(*)	$	14	$	11	$	24	$	20

(*) Excludes any allocation of interest from Southern Power's corporate debt.

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Variable Interest Entity and Equity Method Investments (Tables)

6 Months Ended

Jun. 30, 2018

Regulated Operations [Abstract]

Equity Method Investments

The carrying amounts of Southern Company Gas' equity method investments as of June 30, 2018 and December 31, 2017 and related income from those investments for the three and six-month periods ended June 30, 2018 and June 30, 2017 were as follows:

Investment Balance	June 30, 2018		December 31, 2017
	(in millions)
SNG	$	1,258	$	1,262
Atlantic Coast Pipeline	56		41
PennEast Pipeline	67		57
Triton	42		42
Pivotal JAX LNG, LLC	52		44
Horizon Pipeline	31		30
Other	1		1
Total	$	1,507	$	1,477

Selected financial information of SNG for the three and six months ended June 30, 2018 and June 30, 2017 is as follows:

Income Statement Information	Three Months Ended June 30, 2018		Three Months Ended June 30, 2017		Six Months Ended June 30, 2018		Six Months Ended June 30, 2017
	(in millions)
Revenues	$	146	$	143	$	306	$	298
Operating income	$	60	$	63	$	159	$	147
Net income	$	54	$	48	$	132	$	114

Schedule of Other Nonoperating Income, by Component

Earnings from Equity Method Investments	Three Months Ended June 30, 2018		Three Months Ended June 30, 2017		Six Months Ended June 30, 2018		Six Months Ended June 30, 2017
	(in millions)
SNG	$	27	$	24	$	66	$	58
PennEast Pipeline	1		1		2		4
Atlantic Coast Pipeline	1		2		3		3
Triton	1		2		2		2
Horizon Pipeline	1		—		1		1
Total	$	31	$	29	$	74	$	68

XML

Segment and Related Information (Tables)

6 Months Ended

Jun. 30, 2018

Segment Reporting [Abstract]

Financial Data for Business Segments

Financial data for business segments and products and services for the three and six months ended June 30, 2018 and 2017 was as follows:

	Electric Utilities
	Traditional Electric Operating Companies			Southern Power		Eliminations			Total			Southern Company Gas			All Other			Eliminations			Consolidated
	(in millions)
Three Months Ended June 30, 2018:
Operating revenues	$	4,124		$	555	$	(114	)	$	4,565		$	730		$	381		$	(49	)	$	5,627
Segment net income (loss)(a)(b)(c)	(48		)	22		—			(26		)	(31		)	(100		)	3			(154		)
Six Months Ended June 30, 2018:
Operating revenues	$	8,104		$	1,064	$	(220	)	$	8,948		$	2,369		$	782		$	(100	)	$	11,999
Segment net income (loss)(a)(b)(c)(d)	563			143		—			706			248			(174		)	4			784
At June 30, 2018:
Goodwill	$	—		$	2	$	—		$	2		$	5,015		$	298		$	—		$	5,315
Total assets	73,634			15,428		(313		)	88,749			22,112			3,707			(1,791		)	112,777
Three Months Ended June 30, 2017:
Operating revenues	$	4,157		$	529	$	(101	)	$	4,585		$	716		$	166		$	(37	)	$	5,430
Segment net income (loss)(a)(b)	(1,442		)	82		—			(1,360		)	49			(68		)	(2		)	(1,381		)
Six Months Ended June 30, 2017:
Operating revenues	$	7,943		$	979	$	(206	)	$	8,716		$	2,276		$	289		$	(79	)	$	11,202
Segment net income (loss)(a)(b)(e)	(1,010		)	151		—			(859		)	288			(152		)	—			(723		)
At December 31, 2017:
Goodwill	$	—		$	2	$	—		$	2		$	5,967		$	299		$	—		$	6,268
Total assets	72,204			15,206		(325		)	87,085			22,987			2,552			(1,619		)	111,005

(a) Attributable to Southern Company.

(b) Segment net income (loss) for the traditional electric operating companies includes pre-tax charges for estimated losses on plants under construction of $1.1 billion ($0.8 billion after tax) and $3.0 billion ($2.1 billion after tax) for the three months ended June 30, 2018 and 2017, respectively, and $1.1 billion ($0.8 billion after tax) and $3.1 billion ($2.2 billion after tax) for the six months ended June 30, 2018 and 2017, respectively. See Note 3 to the financial statements of Southern Company under "Kemper County Energy Facility" in Item 8 of the Form 10-K and Note (B) under "Nuclear Construction" and "Kemper County Energy Facility" for additional information.

(c) Segment net income (loss) for Southern Power includes a pre-tax impairment charge of $119 million ($89 million after tax) for the three and six months ended June 30, 2018 related to the pending sale of Southern Power's Florida Plants. See Note (J) under "Southern Power – Sale of Florida Plants" for additional information.

(d) Segment net income (loss) for Southern Company Gas includes a goodwill impairment charge of $42 million for the six months ended June 30, 2018 related to the sale of Pivotal Home Solutions. See Note (J) under "Southern Company Gas – Sale of Pivotal Home Solutions" for additional information.

(e) Segment net income (loss) for the traditional electric operating companies includes a pre-tax charge for the write-down of Gulf Power's ownership of Plant Scherer Unit 3 of $33 million ($20 million after tax) for the six months ended June 30, 2017. See Note 3 to the financial statements of Southern Company under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" in Item 8 of the Form 10-K for additional information.

Business segment financial data for the three and six months ended June 30, 2018 and 2017 was as follows:

	Gas Distribution Operations(a)		Gas Marketing Services(b)(c)			Wholesale Gas Services(d)			Gas Midstream Operations		Total			All Other			Eliminations			Consolidated
	(in millions)
Three Months Ended June 30, 2018:
Operating revenues	$	643	$	89		$	(16	)	$	18	$	734		$	1		$	(5	)	$	730
Segment net income	68		(76		)	(21		)	14		(15		)	(16		)	—			(31		)
Six Months Ended June 30, 2018:
Operating revenues	1,856		359			150			40		2,405			2			(38		)	2,369
Segment net income	216		(63		)	83			38		274			(26		)	—			248
Total assets at June 30, 2018:	18,654		1,610			818			2,269		23,351			11,544			(12,783		)	22,112
Three Months Ended June 30, 2017:
Operating revenues	$	603	$	166		$	(12	)	$	12	$	769		$	3		$	(56	)	$	716
Segment net income	54		4			(17		)	9		50			(1		)	—			49
Six Months Ended June 30, 2017:
Operating revenues	1,783		454			119			37		2,393			5			(122		)	2,276
Segment net income	171		35			51			25		282			6			—			288
Total assets at December 31, 2017:	19,358		2,147			1,096			2,241		24,842			12,184			(14,039		)	22,987

(a) Operating revenues for the three gas distribution operations dispositions were $70 million and $66 million for the three months ended June 30, 2018 and 2017, respectively, and $237 million and $224 million for the six months ended June 30, 2018 and 2017, respectively. See Note (J) under "Southern Company Gas" for additional information.

(b) Operating revenues for the gas marketing services disposition were $24 million and $32 million for the three months ended June 30, 2018 and 2017, respectively, and $55 million and $63 million for the six months ended June 30, 2018 and 2017, respectively. See Note (J) under "Southern Company Gas" for additional information.

(c) Segment net income for gas marketing services includes a loss on disposition of $36 million for the three and six months ended June 30, 2018 and a goodwill impairment charge of $42 million for the six months ended June 30, 2018 recorded in contemplation of the sale of Pivotal Home Solutions. See Note (J) under "Southern Company Gas" for additional information.

(d) The revenues for wholesale gas services are netted with costs associated with its energy and risk management activities. A reconciliation of operating revenues and intercompany revenues is shown in the following table.

	Third Party Gross Revenues		Intercompany Revenues		Total Gross Revenues		Less Gross Gas Costs		Operating Revenues
	(in millions)
Three Months Ended June 30, 2018	$	1,336	$	102	$	1,438	$	1,454	$	(16	)
Three Months Ended June 30, 2017	1,531		123		1,654		1,666		(12		)
Six Months Ended June 30, 2018	$	3,274	$	269	$	3,543	$	3,393	$	150
Six Months Ended June 30, 2017	3,370		259		3,629		3,510		119

Financial Data for Products and Services

Products and Services

	Electric Utilities' Revenues
Period	Retail		Wholesale		Other		Total
	(in millions)
Three Months Ended June 30, 2018	$	3,740	$	611	$	214	$	4,565
Three Months Ended June 30, 2017	3,777		618		190		4,585
Six Months Ended June 30, 2018	$	7,308	$	1,230	$	410	$	8,948
Six Months Ended June 30, 2017	7,171		1,149		396		8,716

	Southern Company Gas' Revenues
Period	Gas Distribution Operations		Gas Marketing Services		Other			Total
	(in millions)
Three Months Ended June 30, 2018	$	638	$	89	$	3		$	730
Three Months Ended June 30, 2017	557		166		(7		)	716
Six Months Ended June 30, 2018	$	1,838	$	359	$	172		$	2,369
Six Months Ended June 30, 2017	1,689		454		133			2,276

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Introduction - Narrative (Details) - USD ($) $ in Millions	1 Months Ended	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Related Party Transaction [Line Items]
Net income (loss)		$ (127)	$ (1,348)	$ 809	$ (684)
Accretion				95
ALABAMA POWER CO
Related Party Transaction [Line Items]
Net income (loss)		262	235	491	412
Increase in ARO due to new CCR rule	$ 1,200
Accretion				$ 41
Inflation rate assumption				4.50%
Trust earnings rate assumption				7.00%
MISSISSIPPI POWER CO
Related Party Transaction [Line Items]
Net income (loss)		47	(2,053)	$ 40	(2,073)
Increase in ARO due to new CCR rule	11
Accretion				2
GEORGIA POWER CO
Related Party Transaction [Line Items]
Net income (loss)		(396)	352	(44)	616
SOUTHERN Co GAS
Related Party Transaction [Line Items]
Net income (loss)		(31)	49	248	288
Wholesale Gas Services | SOUTHERN Co GAS
Related Party Transaction [Line Items]
Inventory write-down		0	$ 0	0	$ 0
Accounting Standards Update 2014-09 | Effect of Change
Related Party Transaction [Line Items]
Net income (loss)		(5)		5
Accounting Standards Update 2014-09 | Effect of Change | SOUTHERN Co GAS
Related Party Transaction [Line Items]
Net income (loss)		$ (5)		$ 5
Plant Farley | ALABAMA POWER CO
Related Party Transaction [Line Items]
Increase in ARO	$ 300

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Introduction - ASC 606 (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017
Condensed Statements of Income
Natural gas revenues	$ 706	$ 684	$ 2,314	$ 2,214
Other revenues	395	184	808	326
Other operations and maintenance	1,559	1,356	3,008	2,740
Operating income (loss)	63	(1,649)	1,439	(397)
Other income (expense), net	78	52	138	98
Earnings (loss) before income taxes	(266)	(1,935)	784	(957)
Income taxes (benefit)	(139)	(587)	(25)	(273)
Net income (loss)	(127)	(1,348)	809	(684)
Consolidated net income attributable to Southern Company	(154)	(1,381)	784	(723)
Condensed Statements of Cash Flows
Net income (loss)	(127)	(1,348)	809	(684)
Changes in certain current assets and liabilities:
Receivables			94	107
Other current assets			(40)	(30)
Accrued taxes			213	(132)
Other current liabilities			125	(14)
Condensed Balance Sheets
Unbilled revenues	769		769		$ 810
Other accounts and notes receivable	621		621		698
Other current assets	172		172		199
Other current liabilities	808		808		874
Retained earnings	8,494		8,494		8,885
Balances Without Adoption of ASC 606
Condensed Statements of Income
Natural gas revenues	713		2,307
Other revenues	393		805
Other operations and maintenance	1,546		2,985
Operating income (loss)	81		1,452
Other income (expense), net	67		118
Earnings (loss) before income taxes	(259)		777
Income taxes (benefit)	(137)		(27)
Net income (loss)	(122)		804
Consolidated net income attributable to Southern Company	(149)		779
Condensed Statements of Cash Flows
Net income (loss)	(122)		804
Changes in certain current assets and liabilities:
Receivables			99
Other current assets			(45)
Accrued taxes			215
Other current liabilities			118
Condensed Balance Sheets
Unbilled revenues	824		824
Other accounts and notes receivable	622		622
Other current assets	116		116
Accrued taxes	542		542
Other current liabilities	815		815
Retained earnings	8,489		8,489
ALABAMA POWER CO
Condensed Statements of Income
Other revenues	69	51	131	108
Other operations and maintenance	402	389	788	772
Operating income (loss)	380	440	752	801
Other income (expense), net	12	15	15	25
Earnings (loss) before income taxes	326	386	636	689
Income taxes (benefit)	64	151	145	277
Net income (loss)	262	235	491	412
Consolidated net income attributable to Southern Company	259	230	484	403
Condensed Statements of Cash Flows
Net income (loss)	262	235	491	412
Changes in certain current assets and liabilities:
Receivables			(153)	(58)
Other current assets			29	12
Accrued taxes			134	52
Other current liabilities			116	7
Condensed Balance Sheets
Unbilled revenues	174		174		162
Other accounts and notes receivable	41		41		55
Other current assets	11		11		5
Other current liabilities	143		143		59
Retained earnings	2,729		2,729		2,647
ALABAMA POWER CO | Balances Without Adoption of ASC 606
Condensed Statements of Income
Other revenues	60		114
Other operations and maintenance	391		767
Operating income (loss)	382		756
Other income (expense), net	10		11
GEORGIA POWER CO
Condensed Statements of Income
Other revenues	120	95	227	191
Other operations and maintenance	457	417	863	816
Operating income (loss)	(472)	621	41	1,105
Other income (expense), net	35	34	73	71
Earnings (loss) before income taxes	(539)	551	(94)	971
Income taxes (benefit)	(143)	199	(50)	355
Net income (loss)	(396)	352	(44)	616
Consolidated net income attributable to Southern Company	(396)	347	(44)	607
Condensed Statements of Cash Flows
Net income (loss)	(396)	352	(44)	616
Changes in certain current assets and liabilities:
Receivables			(103)	(150)
Other current assets			25	(18)
Accrued taxes			(89)	(194)
Other current liabilities			(26)	(6)
Condensed Balance Sheets
Unbilled revenues	276		276		255
Other accounts and notes receivable	81		81		76
Other current assets	23		23		14
Accrued taxes	230		230		344
Other current liabilities	205		205		198
Retained earnings	3,480		3,480		4,215
GEORGIA POWER CO | Balances Without Adoption of ASC 606
Condensed Statements of Income
Other revenues	97		189
Other operations and maintenance	437		828
Operating income (loss)	(475)		38
Other income (expense), net	38		76
Changes in certain current assets and liabilities:
Receivables			(75)
Other current assets			(3)
SOUTHERN Co GAS
Condensed Statements of Income
Natural gas revenues	710	684	2,341	2,205
Other revenues	24	32	55	62
Other operations and maintenance	238	214	514	470
Operating income (loss)	49	95	436	484
Other income (expense), net	3	4	15	10
Earnings (loss) before income taxes	24	80	407	468
Income taxes (benefit)	55	31	159	180
Net income (loss)	(31)	49	248	288
Consolidated net income attributable to Southern Company	(31)	49	248	288
Condensed Statements of Cash Flows
Net income (loss)	(31)	$ 49	248	288
Changes in certain current assets and liabilities:
Receivables			504	418
Other current assets			32	(12)
Accrued taxes			38	(8)
Other current liabilities			24	$ 25
Condensed Balance Sheets
Unbilled revenues	60		60		285
Other accounts and notes receivable	53		53		103
Other current assets	42		42		78
Accrued taxes	63		63		78
Accrued income taxes	86		86		40
Other current liabilities	143		143		159
Retained earnings	(202)		(202)		$ (212)
SOUTHERN Co GAS | Balances Without Adoption of ASC 606
Condensed Statements of Income
Natural gas revenues	717		2,334
Operating income (loss)	56		429
Earnings (loss) before income taxes	31		400
Income taxes (benefit)	57		157
Net income (loss)	(26)		243
Condensed Statements of Cash Flows
Net income (loss)	(26)		243
Changes in certain current assets and liabilities:
Accrued taxes			40
Other current liabilities			17
Condensed Balance Sheets
Accrued income taxes	84		84
Other current liabilities	150		150
Retained earnings	(207)		(207)
Accounting Standards Update 2014-09 | Effect of Change
Condensed Statements of Income
Natural gas revenues	(7)		7
Other revenues	2		3
Other operations and maintenance	13		23
Operating income (loss)	(18)		(13)
Other income (expense), net	11		20
Earnings (loss) before income taxes	(7)		7
Income taxes (benefit)	(2)		2
Net income (loss)	(5)		5
Consolidated net income attributable to Southern Company	(5)		5
Condensed Statements of Cash Flows
Net income (loss)	(5)		5
Changes in certain current assets and liabilities:
Receivables			(5)
Other current assets			5
Accrued taxes			(2)
Other current liabilities			7
Condensed Balance Sheets
Unbilled revenues	(55)		(55)
Other accounts and notes receivable	(1)		(1)
Other current assets	56		56
Accrued taxes	2		2
Other current liabilities	(7)		(7)
Retained earnings	5		5
Accounting Standards Update 2014-09 | ALABAMA POWER CO | Effect of Change
Condensed Statements of Income
Other revenues	9		17
Other operations and maintenance	11		21
Operating income (loss)	(2)		(4)
Other income (expense), net	2		4
Accounting Standards Update 2014-09 | GEORGIA POWER CO | Effect of Change
Condensed Statements of Income
Other revenues	23		38
Other operations and maintenance	20		35
Operating income (loss)	3		3
Other income (expense), net	(3)		(3)
Changes in certain current assets and liabilities:
Receivables			(28)
Other current assets			28
Accounting Standards Update 2014-09 | SOUTHERN Co GAS | Effect of Change
Condensed Statements of Income
Natural gas revenues	(7)		7
Operating income (loss)	(7)		7
Earnings (loss) before income taxes	(7)		7
Income taxes (benefit)	(2)		2
Net income (loss)	(5)		5
Condensed Statements of Cash Flows
Net income (loss)	(5)		5
Changes in certain current assets and liabilities:
Accrued taxes			(2)
Other current liabilities			7
Condensed Balance Sheets
Accrued income taxes	2		2
Other current liabilities	(7)		(7)
Retained earnings	$ 5		$ 5

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Introduction - Asset Retirement Obligation (Details) $ in Millions	6 Months Ended
	Jun. 30, 2018 USD ($)
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at December 31, 2017	$ 4,824
Liabilities incurred	1
Liabilities settled	(97)
Accretion	95
Cash flow revisions	1,493
Reclassification to held for sale	(148)
Balance at June 30, 2018	6,168
ALABAMA POWER CO
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at December 31, 2017	1,709
Liabilities incurred	0
Liabilities settled	(19)
Accretion	41
Cash flow revisions	1,451
Reclassification to held for sale	0
Balance at June 30, 2018	3,182
MISSISSIPPI POWER CO
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at December 31, 2017	174
Liabilities incurred	0
Liabilities settled	(15)
Accretion	2
Cash flow revisions	15
Reclassification to held for sale	0
Balance at June 30, 2018	$ 176

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Introduction - Nuclear Decommissioning (Details) - ALABAMA POWER CO - Plant Farley $ in Millions	6 Months Ended
	Jun. 30, 2018 USD ($)
Public Utility, Property, Plant and Equipment [Line Items]
Beginning year	2037
Completion year	2076
Site study costs	$ 1,720
Radiated structures
Public Utility, Property, Plant and Equipment [Line Items]
Site study costs	1,621
Non-radiated structures
Public Utility, Property, Plant and Equipment [Line Items]
Site study costs	$ 99

XML

Introduction - Goodwill (Details) - USD ($) $ in Millions	3 Months Ended			6 Months Ended
	Jun. 30, 2018	Mar. 31, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Goodwill [Roll Forward]
Balance at December 31, 2017		$ 6,268		$ 6,268
Impairment				(42)
Sale of Pivotal Home Solutions				(242)
Reclassification to held for sale				(668)
Balance at June 30, 2018	$ 5,315			5,315
SOUTHERN Co GAS
Goodwill [Roll Forward]
Balance at December 31, 2017		5,967		5,967
Impairment	0	(42)	$ 0	(42)	$ 0
Sale of Pivotal Home Solutions				(242)
Reclassification to held for sale				(668)
Balance at June 30, 2018	5,015			5,015
SOUTHERN Co GAS | Gas Distribution Operations
Goodwill [Roll Forward]
Balance at December 31, 2017		4,702		4,702
Impairment				0
Sale of Pivotal Home Solutions				0
Reclassification to held for sale				(668)
Balance at June 30, 2018	4,034			4,034
SOUTHERN Co GAS | Gas Marketing Services
Goodwill [Roll Forward]
Balance at December 31, 2017		$ 1,265		1,265
Impairment				(42)
Sale of Pivotal Home Solutions				(242)
Reclassification to held for sale				0
Balance at June 30, 2018	$ 981			$ 981

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Introduction - Other Intangibles (Details) - USD ($) $ in Millions	Jun. 30, 2018	Dec. 31, 2017
Indefinite-lived Intangible Assets [Line Items]
Accumulated Amortization	$ (205)	$ (186)
Total other intangible assets - net	702	873
Southern Company
Indefinite-lived Intangible Assets [Line Items]
Gross Carrying Amount	832	984
Accumulated Amortization	(205)	(186)
Other Intangible Assets, Net	627	798
Total other intangible assets - gross	907	1,059
Total other intangible assets - net	702	873
Customer relationships | Southern Company
Indefinite-lived Intangible Assets [Line Items]
Gross Carrying Amount	223	288
Accumulated Amortization	(79)	(83)
Other Intangible Assets, Net	144	205
Trade names | Southern Company
Indefinite-lived Intangible Assets [Line Items]
Gross Carrying Amount	70	159
Accumulated Amortization	(17)	(17)
Other Intangible Assets, Net	53	142
Storage and transportation contracts | Southern Company
Indefinite-lived Intangible Assets [Line Items]
Gross Carrying Amount	64	64
Accumulated Amortization	(44)	(34)
Other Intangible Assets, Net	20	30
PPA fair value adjustments | Southern Company
Indefinite-lived Intangible Assets [Line Items]
Gross Carrying Amount	456	456
Accumulated Amortization	(60)	(47)
Other Intangible Assets, Net	396	409
Other | Southern Company
Indefinite-lived Intangible Assets [Line Items]
Gross Carrying Amount	19	17
Accumulated Amortization	(5)	(5)
Other Intangible Assets, Net	14	12
Federal Communications Commission licenses | Southern Company
Indefinite-lived Intangible Assets [Line Items]
Other intangible assets not subject to amortization	75	75
SOUTHERN POWER CO
Indefinite-lived Intangible Assets [Line Items]
Accumulated Amortization	(60)	(47)
SOUTHERN POWER CO | PPA fair value adjustments
Indefinite-lived Intangible Assets [Line Items]
Gross Carrying Amount	456	456
Accumulated Amortization	(60)	(47)
Other Intangible Assets, Net	396	409
SOUTHERN Co GAS
Indefinite-lived Intangible Assets [Line Items]
Gross Carrying Amount	246	400
Accumulated Amortization	(121)	(120)
Other Intangible Assets, Net	125	280
Total other intangible assets - net	125	280
SOUTHERN Co GAS | Customer relationships
Indefinite-lived Intangible Assets [Line Items]
Gross Carrying Amount	156	221
Accumulated Amortization	(71)	(77)
Other Intangible Assets, Net	85	144
SOUTHERN Co GAS | Trade names
Indefinite-lived Intangible Assets [Line Items]
Gross Carrying Amount	26	115
Accumulated Amortization	(6)	(9)
Other Intangible Assets, Net	20	106
SOUTHERN Co GAS | Storage and transportation contracts
Indefinite-lived Intangible Assets [Line Items]
Gross Carrying Amount	64	64
Accumulated Amortization	(44)	(34)
Other Intangible Assets, Net	$ 20	$ 30

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Introduction - Intangibles, Amortization (Details) - USD ($) $ in Millions	3 Months Ended	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2018
Finite-Lived Intangible Assets [Line Items]
Amortization of intangible assets	$ 23	$ 50
SOUTHERN POWER CO
Finite-Lived Intangible Assets [Line Items]
Amortization of intangible assets	6	13
SOUTHERN Co GAS
Finite-Lived Intangible Assets [Line Items]
Amortization of intangible assets	$ 14	$ 31

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Introduction - Restricted Cash (Details) - USD ($) $ in Millions	Jun. 30, 2018	Dec. 31, 2017	Jun. 30, 2017	Dec. 31, 2016
Restricted Cash and Cash Equivalents Items [Line Items]
Cash and cash equivalents	$ 1,980	$ 2,130
Restricted cash:
Total cash, cash equivalents, and restricted cash	2,017	2,147	$ 1,455	$ 1,992
SOUTHERN Co GAS
Restricted Cash and Cash Equivalents Items [Line Items]
Cash and cash equivalents	69	73
Cash and cash equivalents classified as assets held for sale	0
Restricted cash:
Other accounts and notes receivable	6	5
Deferred charges and other assets		0
Total cash, cash equivalents, and restricted cash	75	78	43	24
SOUTHERN POWER CO
Restricted Cash and Cash Equivalents Items [Line Items]
Cash and cash equivalents	142	129
Restricted cash:
Other accounts and notes receivable		0
Deferred charges and other assets		11
Total cash, cash equivalents, and restricted cash	142	140	$ 116	$ 1,112
Southern Company
Restricted Cash and Cash Equivalents Items [Line Items]
Cash and cash equivalents	1,980	2,130
Cash and cash equivalents classified as assets held for sale	31
Restricted cash:
Other accounts and notes receivable	6	5
Deferred charges and other assets		12
Total cash, cash equivalents, and restricted cash	$ 2,017	$ 2,147

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Contingencies and Regulatory Matters - General (Details) $ in Thousands						6 Months Ended
	Jun. 12, 2018 USD ($)	May 18, 2018 USD ($)	May 14, 2018 USD ($)	Mar. 02, 2018 USD ($) generating_plant	Feb. 07, 2018	Jun. 30, 2018 USD ($)	Dec. 31, 2017 USD ($)
ALABAMA POWER CO
Loss Contingencies [Line Items]
Public utilities, approved return on equity percentage						46.60%
MISSISSIPPI POWER CO
Loss Contingencies [Line Items]
Public utilities, requested return on equity, percentage					9.33%
GEORGIA POWER CO
Loss Contingencies [Line Items]
Environmental remediation liability						$ 25,000	$ 22,000
GULF POWER CO
Loss Contingencies [Line Items]
Environmental remediation liability						48,000	52,000
SOUTHERN Co GAS
Loss Contingencies [Line Items]
Environmental remediation liability						$ 305,000	388,000
RE Roserock, LLC | SOUTHERN POWER CO
Loss Contingencies [Line Items]
Ownership percentage by parent						51.00%
Location One | SOUTHERN Co GAS
Loss Contingencies [Line Items]
Environmental remediation liability						$ 2,000
Location One | SOUTHERN Co GAS | Elizabethtown Gas
Loss Contingencies [Line Items]
Environmental remediation liability						$ 77,000	$ 85,000
Alabama Department of Environmental Management (ADEM) | ALABAMA POWER CO
Loss Contingencies [Line Items]
Litigation settlement, amount awarded to other party				$ 1,250
Number of electric generating plants | generating_plant				5
Deepwater Horizon Oil Spill Litigation Case | MISSISSIPPI POWER CO
Loss Contingencies [Line Items]
Litigation settlement awarded from other party			$ 18,000
Martin Product Sales, LLC Litigation | MISSISSIPPI POWER CO
Loss Contingencies [Line Items]
Damages sought by litigation		$ 143,000
Nicor Energy Services Company Litigation | SOUTHERN Co GAS
Loss Contingencies [Line Items]
Litigation amount awarded to other party	$ 11,000
Open Access Transmission Tariff
Loss Contingencies [Line Items]
Public utilities, approved return on equity percentage						11.25%
Public utilities, requested return on equity, percentage						8.65%

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Contingencies and Regulatory Matters - Alabama Power (Details) - USD ($) $ in Millions	Aug. 06, 2018	Jun. 30, 2018	Dec. 31, 2017
ALABAMA POWER CO | Deferred under recovered regulatory clause revenues
Loss Contingencies [Line Items]
Rate CNP Compliance		$ 30	$ 17
Rate CNP PPA		11	12
Retail Energy Cost Recovery		80	25
ALABAMA POWER CO | Under recovered regulatory clause revenues
Loss Contingencies [Line Items]
Retail Energy Cost Recovery		28	0
ALABAMA POWER CO | Other regulatory liabilities, deferred
Loss Contingencies [Line Items]
Natural Disaster Reserve		$ 30	$ 38
Plant Greene County Units 1 and 2 | Reserve Margin Plan | Subsequent Event | MISSISSIPPI POWER CO
Loss Contingencies [Line Items]
Accelerated retirement period	4 years

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Contingencies and Regulatory Matters - Alabama Power Narrative (Details) - ALABAMA POWER CO $ in Millions				6 Months Ended	12 Months Ended
	Jan. 01, 2019 $ / KWH_Kilowatt_hour	May 01, 2018 USD ($) $ / KWH_Kilowatt_hour	Apr. 30, 2018 $ / KWH_Kilowatt_hour	Jun. 30, 2018 USD ($)	Dec. 31, 2025	Dec. 31, 2018 USD ($)	May 08, 2018 USD ($)
Loss Contingencies [Line Items]
Public utilities, approved return on equity percentage				46.60%
Public utilities, allowed weighted common equity return, percentage		6.15%	6.21%
Customer refundable fees, refund payments, tranche one, percentage				25.00%
Customer refundable fees, refund payments, tranche two, percentage				40.00%
Customer refundable fees, refund payments, tranche three, percentage				75.00%
Customer refund liability, noncurrent							$ 50
Customer refund liability, current							$ 257
Current billing rates under rate ecr in terms of per units | $ / KWH_Kilowatt_hour		2.353	2.015
Approved increase (decrease) in fuel rates amount		$ 100
Tax Cuts and Jobs Act of 2017, change in tax rate, deferred tax liability, income tax benefit, maximum amount used to offset under recovered amounts		$ 30
Tax Cuts and Jobs Act of 2017, change in tax rate, deferred tax liability, income tax benefit				$ 30
Minimum
Loss Contingencies [Line Items]
Public utilities, actual weighted common equity return, threshold, percentage				6.15%
Public utilities, actual weighted common equity return, threshold for customer refundable fees, refund payments, percentage, tranche one				6.15%
Public utilities, actual weighted common equity return, threshold for customer refundable fees, refund payments, percentage, tranche two				6.65%
Public utilities, actual weighted common equity return, threshold for customer refundable fees, refund payments, percentage, tranche three				7.15%
Maximum
Loss Contingencies [Line Items]
Public utilities, actual weighted common equity return, threshold, percentage				7.65%
Public utilities, actual weighted common equity return, threshold for customer refundable fees, refund payments, percentage, tranche one				6.65%
Public utilities, actual weighted common equity return, threshold for customer refundable fees, refund payments, percentage, tranche two				7.15%
Public utilities, actual weighted common equity return, threshold for customer refundable fees, refund payments, percentage, tranche three				7.65%
Customer refundable fees, refund payments, percentage				7.65%
Scenario, Forecast
Loss Contingencies [Line Items]
Public utilities, approved return on equity percentage					55.00%
Current billing rates under rate ecr in terms of per units | $ / KWH_Kilowatt_hour	5.910
Tax Cuts and Jobs Act of 2017, change in tax rate, deferred tax liability, income tax benefit						$ 50

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Contingencies and Regulatory Matters - Georgia Power (Details) $ in Millions		1 Months Ended			6 Months Ended		12 Months Ended
	Apr. 03, 2018 USD ($)	Feb. 29, 2020 USD ($)	Jun. 30, 2019 USD ($)	Oct. 31, 2018 USD ($)	Jun. 30, 2018 USD ($)	Jun. 30, 2017 USD ($)	Dec. 31, 2019	Dec. 31, 2017 USD ($)
Loss Contingencies [Line Items]
Effective tax rate					(3.20%)	(28.60%)
Deferred income tax expense (benefit)					$ (338)	$ (270)
GEORGIA POWER CO
Loss Contingencies [Line Items]
Customer refund	$ 330
Effective tax rate					(53.50%)	36.60%
Deferred income tax expense (benefit)	(700)				$ (256)	$ 159
Customer refund liability in absence of base rate case	$ 185
Under recovered fuel balance, threshold for interim fuel rider					200
GEORGIA POWER CO | Maximum
Loss Contingencies [Line Items]
Retail regulatory equity ratio	0.55
GEORGIA POWER CO | Other current liabilities
Loss Contingencies [Line Items]
Over (under) recovered fuel balance					$ (159)			$ (165)
State and Local Jurisdiction | GEORGIA POWER CO
Loss Contingencies [Line Items]
Effective tax rate	6.00%
Scenario, Forecast | GEORGIA POWER CO
Loss Contingencies [Line Items]
Customer refundable fees, refund payments		$ 103	$ 96	$ 131
Scenario, Forecast | State and Local Jurisdiction | GEORGIA POWER CO
Loss Contingencies [Line Items]
Effective tax rate							5.75%

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Contingencies and Regulatory Matters - Gulf Power (Details) - GULF POWER CO $ in Millions			3 Months Ended	6 Months Ended
	Mar. 26, 2018 USD ($)	Mar. 25, 2018	Jun. 30, 2018 USD ($)	Jun. 30, 2018 USD ($)	Jun. 30, 2017 USD ($)	Dec. 31, 2017 USD ($)
Loss Contingencies [Line Items]
Tax reform settlement agreement, annual reduction of revenue from base rates	$ 18.2
Tax reform settlement agreement, annual reduction of revenue from environmental cost recovery rates	15.6
Tax reform settlement agreement, refund	$ 69.4
Customer refundable fees, refund payments			$ 28.0
Retail regulatory equity ratio	0.535	0.525
Environmental Cost Recovery			10.0	$ 10.0		$ 11.0
Projected environmental expenditures				11.0	$ 13.0
Property Basis Differences
Loss Contingencies [Line Items]
Deferred tax asset, regulatory liability			5.0	5.0
Under recovered regulatory clause revenues
Loss Contingencies [Line Items]
Fuel Cost Recovery			0.0	0.0		22.0
Purchased Power Capacity Recovery			2.0	2.0		2.0
Environmental Cost Recovery			1.0	1.0		2.0
Other regulatory liabilities, current
Loss Contingencies [Line Items]
Fuel Cost Recovery			5.0	5.0		0.0
Energy Conservation Cost Recovery			$ 1.0	$ 1.0		$ 0.0

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Contingencies and Regulatory Matters - Mississippi Power (Details) - USD ($)					3 Months Ended			6 Months Ended		12 Months Ended
	Jul. 27, 2018	May 08, 2018	Mar. 22, 2018	Feb. 07, 2018	Sep. 30, 2018	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Aug. 03, 2018
Loss Contingencies [Line Items]
Retail electric revenues						$ 3,740,000,000	$ 3,777,000,000	$ 7,308,000,000	$ 7,171,000,000
MISSISSIPPI POWER CO
Loss Contingencies [Line Items]
Performance evaluation plan, prior year lookback, surcharge (refund)			$ 0								$ 5,000,000	$ 5,000,000	$ 0	$ 0
Public utilities, interim rate increase (decrease), percentage								4.00%		0.00%	0.00%
Public utilities, interim rate								$ 38,000,000
Public utilities, requested revenue requirement increase (decrease), amount				$ 26,000,000
Public utilities, requested return on equity, percentage				9.33%
Performance evaluation plan, equity ratio				55.00%
Retail electric revenues						$ 212,000,000	$ 222,000,000	$ 406,000,000	$ 422,000,000
Increase retail base rate, annual base revenue		$ 3,000,000
Ad valorem tax adjustment, annual rate increase, percentage		0.80%
Ad valorem tax adjustment, annual rate increase, amount		$ 7,000,000
PEP Settlement Agreement | MISSISSIPPI POWER CO
Loss Contingencies [Line Items]
Public utilities, approved return on equity percentage								43.50%
Subsequent Event | MISSISSIPPI POWER CO
Loss Contingencies [Line Items]
Environmental compliance overview plan, maximum annual increase in revenue, amount															$ 17,000,000
Subsequent Event | PEP Settlement Agreement
Loss Contingencies [Line Items]
Public utilities, requested revenue requirement increase (decrease), compensation costs, amount	$ 5,500,000
Subsequent Event | PEP Settlement Agreement | MISSISSIPPI POWER CO
Loss Contingencies [Line Items]
Public utilities, approved revenue requirement increase (decrease), amount	$ 21,600,000
Public utilities, performance-adjusted allowed return on equity percentage	9.31%
Deferred income taxes	$ 44,000,000
Equity ratio, variance threshold	1.00%
Subsequent Event | Scenario, Forecast | PEP Settlement Agreement | MISSISSIPPI POWER CO
Loss Contingencies [Line Items]
Retail electric revenues					$ 5,000,000
Maximum | Subsequent Event | PEP Settlement Agreement | MISSISSIPPI POWER CO
Loss Contingencies [Line Items]
Public utilities, approved return on equity percentage	50.00%

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Contingencies and Regulatory Matters - Southern Company Gas (Details) - USD ($) $ in Millions								1 Months Ended	3 Months Ended
	Jun. 22, 2018	May 15, 2018	May 02, 2018	Mar. 28, 2018	Mar. 26, 2018	Feb. 23, 2018	Feb. 15, 2018	Oct. 31, 2017	Mar. 31, 2018
Florida City Gas
Loss Contingencies [Line Items]
Public utilities, requested rate increase (decrease), amount								$ (19.0)
Public utilities, interim rate								$ 5.0
Public utilities, requested rate increase (decrease), amended, amount					$ 11.5
Public utilities, requested return on equity, percentage					10.19%
Public utilities, interim rate increase (decrease), percentage		4.00%
Public utilities, approved return on equity percentage		55.00%
Atlanta Gas Light
Loss Contingencies [Line Items]
Public utilities, requested rate increase (decrease), amount						$ 16.0
Customer credit		$ 8.0
Atlanta Gas Light | Pipeline Replacement Program
Loss Contingencies [Line Items]
Litigation settlement awarded from other party									$ 7.0
Nicor Gas
Loss Contingencies [Line Items]
Approved increase (decrease) in fuel rates amount			$ (44.0)
Public utilities, approved return on equity percentage			9.80%
Chattanooga Gas
Loss Contingencies [Line Items]
Public utilities, requested rate increase (decrease), amount							$ (7.0)
Public utilities, requested return on equity, percentage							11.25%
Elizabeth Gas
Loss Contingencies [Line Items]
Approved increase (decrease) in fuel rates amount	$ (12.0)
Elkton Gas
Loss Contingencies [Line Items]
Approved increase (decrease) in fuel rates amount				$ (0.1)
Minimum | Florida City Gas
Loss Contingencies [Line Items]
Public utilities, requested return on equity, percentage						10.55%
Maximum | Florida City Gas
Loss Contingencies [Line Items]
Public utilities, requested return on equity, percentage		10.95%

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Contingencies and Regulatory Matters - Nuclear Construction (Details) - GEORGIA POWER CO $ in Millions								6 Months Ended	12 Months Ended				48 Months Ended	102 Months Ended
	Jan. 01, 2021	Jan. 01, 2020	Aug. 31, 2018 USD ($)	Apr. 03, 2018 USD ($)	Feb. 28, 2018 USD ($)	Jan. 11, 2018 USD ($)	Jan. 01, 2016	Jun. 30, 2018 USD ($) subcontractor	Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2009 USD ($) utility MW	Dec. 31, 2022 USD ($)	Jun. 30, 2017 USD ($)	Jun. 01, 2021	Sep. 30, 2017 USD ($)	Dec. 31, 2013
Loss Contingencies [Line Items]
Number of construction units approved | utility												2
Electric generating capacity in mega watts under consortium agreement | MW												1,100
Estimated in-service capital cost												$ 4,418
Financing costs collected, net of tax								$ 1,700
Additional construction capital costs						$ 3,300
Amendment to estimated in-service capital cost						$ 5,680
Retail rate of return on common equity																	10.95%
Customer refund				$ 330
Eligible project costs to be reimbursed								3,460
Plant Vogtle Units 3 And 4
Loss Contingencies [Line Items]
Construction financing costs								1,700
Increase in base project capital cost forecast								700
Estimated project costs								1,100
Increase in expected costs								800
Base project capital cost forecast, monthly								50
Monthly AFUDC								$ 12
Percentage of ownership interest required for voting for continuing construction								90.00%
Public utilities, increase in construction budget								$ 1,000
Extension in project schedule								1 year
Percentage of approval required to change primary construction contractor								90.00%
Percentage of approval required for material amendments								67.00%
Cost settlement agreement revised forecast, net of payments								$ 7,300
Additional construction capital costs					$ 448									$ 4,400
Public utilities, approved return on equity percentage							10.00%
Return on equity reduction, negative impact on earnings											$ 25
Guarantor obligations											1,700
Customer refund											$ 188
Scenario, Forecast | Plant Vogtle Units 3 And 4
Loss Contingencies [Line Items]
Construction financing costs									$ 3,200
Public utilities, approved return on equity percentage	5.30%	8.30%
Monthly reduction of ROE to calculate NCRR tariff															0.10%
Return on equity reduction, negative impact on earnings										$ 100			$ 585
Requested capital construction costs			$ 578
Vogtle Owners | Plant Vogtle Units 3 And 4
Loss Contingencies [Line Items]
Period of notice required in the event letters of credit are not renewed								30 days
FFB Loan
Loss Contingencies [Line Items]
Long-term line of credit								$ 2,600
Conditional borrowing commitment																$ 1,670
Minimum | Plant Vogtle Units 3 And 4
Loss Contingencies [Line Items]
Number of subcontractors | subcontractor								60

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Contingencies and Regulatory Matters - Nuclear Construction Cost and Schedule (Details) - GEORGIA POWER CO - USD ($) $ in Millions		6 Months Ended	12 Months Ended
	Apr. 03, 2018	Jun. 30, 2018	Dec. 31, 2017
Loss Contingencies [Line Items]
Customer refund	$ 330
Plant Vogtle Units 3 And 4
Loss Contingencies [Line Items]
Base project capital cost forecast		$ 8,000
Construction contingency estimate		400
Project capital cost forecast		8,400
Net investment as of June 30, 2018		(4,000)
Remaining estimate to complete		4,400
Expected capitalized costs		$ 350
Guarantor obligations			$ 1,700
Customer refund			$ 188

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Contingencies and Regulatory Matters - Kemper County Energy Facility (Details) - MISSISSIPPI POWER CO - USD ($) $ in Millions		3 Months Ended	6 Months Ended		12 Months Ended
	Aug. 06, 2018	Jun. 30, 2018	Dec. 31, 2018	Jun. 30, 2018	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2017
Loss Contingencies [Line Items]
Accrued plant closure costs		$ 42		$ 42			$ 35
Kemper County Energy Facility
Loss Contingencies [Line Items]
Public utilities, property, plant and equipment, amount of loss (recovery) on plant abandonment		0		45
Public utilities, property, plant and equipment, amount of loss (recovery) on plant abandonment after tax				33
Accrued plant closure costs		$ 25		$ 25
Scenario, Forecast | Kemper County Energy Facility
Loss Contingencies [Line Items]
Production costs, period cost			$ 4		$ 4	$ 7
Subsequent Event | Reserve Margin Plan | Plant Watson, Unit 4
Loss Contingencies [Line Items]
Accelerated retirement period	2 years
Subsequent Event | Reserve Margin Plan | Plant Watson, Unit 5
Loss Contingencies [Line Items]
Accelerated retirement period	7 years
Subsequent Event | Reserve Margin Plan | Plant Greene County Units 1 and 2
Loss Contingencies [Line Items]
Accelerated retirement period	4 years

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Contingencies and Regulatory Matters - Other Matters (Details)	6 Months Ended
	Jun. 30, 2018 USD ($)
Southern Company Holdings Subsidiary
Loss Contingencies [Line Items]
Leveraged leases, balance sheet, investment in leveraged leases	$ 86,000,000
SOUTHERN Co GAS
Loss Contingencies [Line Items]
Impairment of long-lived assets	0
Natural Gas Storage
Loss Contingencies [Line Items]
Public utilities, property, plant and equipment, net	$ 111,000,000
Natural Gas Storage - Salt Dome Caverns
Loss Contingencies [Line Items]
Public utilities, property, plant and equipment, percentage of total	20.00%

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Revenue from Contracts with Customers - Disaggregate Revenue Sources (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Disaggregation of Revenue [Line Items]
Total operating revenues	$ 5,627	$ 5,430	$ 11,999	$ 11,202
Other Income	89		183
Retail electric revenues
Disaggregation of Revenue [Line Items]
Lease income	18		36
Increase (decrease) in revenue from cost recovery mechanisms	68		101
Residential
Disaggregation of Revenue [Line Items]
Total operating revenues	1,579		3,118
Commercial
Disaggregation of Revenue [Line Items]
Total operating revenues	1,315		2,557
Industrial
Disaggregation of Revenue [Line Items]
Total operating revenues	814		1,569
Other
Disaggregation of Revenue [Line Items]
Total operating revenues	32		64
Natural gas distribution revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	642		1,865
Alternative revenue programs
Disaggregation of Revenue [Line Items]
Total operating revenues	(4)		(27)
Total retail electric and gas distribution revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	4,378		9,146
Wholesale energy revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	459		928
Revenue from transactions accounted for as derivatives	61		155
Lease income from PPA contracts	118		187
Wholesale capacity revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	152		302
Lease income from PPA contracts	31		61
Other natural gas revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	68		476
Other revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	570		1,147
SOUTHERN Co GAS
Disaggregation of Revenue [Line Items]
Total operating revenues	730	716	2,369	2,276
SOUTHERN Co GAS | Natural gas distribution revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	638		1,838
SOUTHERN Co GAS | Residential
Disaggregation of Revenue [Line Items]
Total operating revenues	273		933
SOUTHERN Co GAS | Commercial
Disaggregation of Revenue [Line Items]
Total operating revenues	76		268
SOUTHERN Co GAS | Transportation
Disaggregation of Revenue [Line Items]
Total operating revenues	7		24
SOUTHERN Co GAS | Industrial
Disaggregation of Revenue [Line Items]
Total operating revenues	228		505
SOUTHERN Co GAS | Other
Disaggregation of Revenue [Line Items]
Total operating revenues	58		135
SOUTHERN Co GAS | Alternative revenue programs
Disaggregation of Revenue [Line Items]
Total operating revenues	(4)		(27)
SOUTHERN Co GAS | Other revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	0		1
SOUTHERN Co GAS | Gas Marketing Services
Disaggregation of Revenue [Line Items]
Total operating revenues	89		359
Other Income			4
SOUTHERN Co GAS | Wholesale gas services
Disaggregation of Revenue [Line Items]
Total operating revenues	(15)		131
SOUTHERN Co GAS | Gas midstream operations
Disaggregation of Revenue [Line Items]
Total operating revenues	18		40
ALABAMA POWER CO
Disaggregation of Revenue [Line Items]
Total operating revenues	1,503	1,484	2,976	2,866
Other Income	26		52
ALABAMA POWER CO | Retail electric revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	1,338		2,624
Increase (decrease) in revenue from cost recovery mechanisms	78		125
ALABAMA POWER CO | Residential
Disaggregation of Revenue [Line Items]
Total operating revenues	557		1,127
ALABAMA POWER CO | Commercial
Disaggregation of Revenue [Line Items]
Total operating revenues	402		774
ALABAMA POWER CO | Industrial
Disaggregation of Revenue [Line Items]
Total operating revenues	372		710
ALABAMA POWER CO | Other
Disaggregation of Revenue [Line Items]
Total operating revenues	7		13
ALABAMA POWER CO | Wholesale energy revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	71		172
Revenue from transactions accounted for as derivatives	4		9
ALABAMA POWER CO | Wholesale capacity revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	25		49
ALABAMA POWER CO | Other revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	69		131
GEORGIA POWER CO
Disaggregation of Revenue [Line Items]
Total operating revenues	2,048	2,048	4,008	3,880
Other Income	26		53
GEORGIA POWER CO | Retail electric revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	1,889		3,688
Lease income	18		36
Increase (decrease) in revenue from cost recovery mechanisms	3		12
GEORGIA POWER CO | Residential
Disaggregation of Revenue [Line Items]
Total operating revenues	785		1,529
GEORGIA POWER CO | Commercial
Disaggregation of Revenue [Line Items]
Total operating revenues	749		1,466
GEORGIA POWER CO | Industrial
Disaggregation of Revenue [Line Items]
Total operating revenues	335		650
GEORGIA POWER CO | Other
Disaggregation of Revenue [Line Items]
Total operating revenues	20		43
GEORGIA POWER CO | Wholesale energy revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	26		66
Revenue from transactions accounted for as derivatives	5		13
GEORGIA POWER CO | Wholesale capacity revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	13		27
GEORGIA POWER CO | Other revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	120		227
Lease income	33		66
GULF POWER CO
Disaggregation of Revenue [Line Items]
Total operating revenues	344	357	692	707
Other Income	2		4
GULF POWER CO | Retail electric revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	301		591
Increase (decrease) in revenue from cost recovery mechanisms	(12)		(28)
GULF POWER CO | Residential
Disaggregation of Revenue [Line Items]
Total operating revenues	172		337
GULF POWER CO | Commercial
Disaggregation of Revenue [Line Items]
Total operating revenues	96		188
GULF POWER CO | Industrial
Disaggregation of Revenue [Line Items]
Total operating revenues	31		63
GULF POWER CO | Other
Disaggregation of Revenue [Line Items]
Total operating revenues	2		3
GULF POWER CO | Wholesale energy revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	21		56
GULF POWER CO | Wholesale capacity revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	6		12
GULF POWER CO | Other revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	16		33
MISSISSIPPI POWER CO
Disaggregation of Revenue [Line Items]
Total operating revenues	297	303	598	575
MISSISSIPPI POWER CO | Retail electric revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	212		406
Increase (decrease) in revenue from cost recovery mechanisms	(1)		(8)
MISSISSIPPI POWER CO | Residential
Disaggregation of Revenue [Line Items]
Total operating revenues	65		125
MISSISSIPPI POWER CO | Commercial
Disaggregation of Revenue [Line Items]
Total operating revenues	68		130
MISSISSIPPI POWER CO | Industrial
Disaggregation of Revenue [Line Items]
Total operating revenues	76		146
MISSISSIPPI POWER CO | Other
Disaggregation of Revenue [Line Items]
Total operating revenues	3		5
MISSISSIPPI POWER CO | Wholesale energy revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	73		167
MISSISSIPPI POWER CO | Wholesale capacity revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	1		5
MISSISSIPPI POWER CO | Other revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	11		20
SOUTHERN POWER CO
Disaggregation of Revenue [Line Items]
Total operating revenues	555	529	1,064	979
SOUTHERN POWER CO | Other revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	3		5
SOUTHERN POWER CO | PPA capacity revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	144		282
Lease income from PPA contracts	47		94
SOUTHERN POWER CO | PPA energy revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	302		556
Revenue from transactions accounted for as derivatives	50		129
Lease income from PPA contracts	127		203
SOUTHERN POWER CO | Non-PPA revenues
Disaggregation of Revenue [Line Items]
Total operating revenues	106		221
Operating Segments | SOUTHERN Co GAS
Disaggregation of Revenue [Line Items]
Total operating revenues	734	769	2,405	2,393
Wholesale gas services | Operating Segments | SOUTHERN Co GAS
Disaggregation of Revenue [Line Items]
Total operating revenues	(16)	(12)	150	119
Wholesale gas services | Third Party Gross Revenues | Operating Segments | SOUTHERN Co GAS
Disaggregation of Revenue [Line Items]
Total operating revenues	1,336	$ 1,531	3,274	$ 3,370
Revenue from transactions accounted for as derivatives	$ 700		$ 1,800

XML

Revenue from Contracts with Customers - Contract Balances (Details) $ in Millions	6 Months Ended
	Jun. 30, 2018 USD ($)
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Receivables	$ 2,785
Contract Assets	33
Contract Liabilities	36
ALABAMA POWER CO
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Receivables	603
Contract Assets	0
Contract Liabilities	10
GEORGIA POWER CO
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Receivables	840
Contract Assets	9
Contract Liabilities	$ 9
Performance obligation, expected timing of satisfaction	1 year
GULF POWER CO
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Receivables	$ 169
Contract Assets	0
Contract Liabilities	1
MISSISSIPPI POWER CO
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Receivables	83
Contract Assets	0
Contract Liabilities	0
SOUTHERN POWER CO
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Receivables	136
Contract Assets	0
Contract Liabilities	4
SOUTHERN Co GAS
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Receivables	570
Contract Assets	0
Contract Liabilities	1
Unregulated Distributed Generation
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Contract Assets	23
Contract Liabilities	$ 16

XML

Revenue from Contracts with Customers - Performance Obligations (Details) $ in Millions	6 Months Ended
	Jun. 30, 2018 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2018-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 263
Performance obligation, expected timing of satisfaction	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 352
Performance obligation, expected timing of satisfaction	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 322
Performance obligation, expected timing of satisfaction	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 322
Performance obligation, expected timing of satisfaction	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 310
Performance obligation, expected timing of satisfaction	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 1,960
Performance obligation, expected timing of satisfaction
ALABAMA POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2018-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 11
Performance obligation, expected timing of satisfaction	1 year
ALABAMA POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 22
Performance obligation, expected timing of satisfaction	1 year
ALABAMA POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 22
Performance obligation, expected timing of satisfaction	1 year
ALABAMA POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 26
Performance obligation, expected timing of satisfaction	1 year
ALABAMA POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 23
Performance obligation, expected timing of satisfaction	1 year
ALABAMA POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 161
Performance obligation, expected timing of satisfaction
GEORGIA POWER CO
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Performance obligation, expected timing of satisfaction	1 year
GEORGIA POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2018-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 20
Performance obligation, expected timing of satisfaction	1 year
GEORGIA POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 41
Performance obligation, expected timing of satisfaction	1 year
GEORGIA POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 38
Performance obligation, expected timing of satisfaction	1 year
GEORGIA POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 40
Performance obligation, expected timing of satisfaction	1 year
GEORGIA POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 30
Performance obligation, expected timing of satisfaction	1 year
GEORGIA POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 113
Performance obligation, expected timing of satisfaction
GULF POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2018-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 11
Performance obligation, expected timing of satisfaction	1 year
GULF POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 22
Performance obligation, expected timing of satisfaction	1 year
GULF POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 0
Performance obligation, expected timing of satisfaction	1 year
GULF POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 0
Performance obligation, expected timing of satisfaction	1 year
GULF POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 0
Performance obligation, expected timing of satisfaction	1 year
GULF POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 0
Performance obligation, expected timing of satisfaction
MISSISSIPPI POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2018-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 2
Performance obligation, expected timing of satisfaction	1 year
MISSISSIPPI POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 3
Performance obligation, expected timing of satisfaction	1 year
MISSISSIPPI POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 3
Performance obligation, expected timing of satisfaction	1 year
MISSISSIPPI POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 1
Performance obligation, expected timing of satisfaction	1 year
MISSISSIPPI POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 0
Performance obligation, expected timing of satisfaction	1 year
MISSISSIPPI POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 0
Performance obligation, expected timing of satisfaction
SOUTHERN POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2018-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 211
Performance obligation, expected timing of satisfaction	1 year
SOUTHERN POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 310
Performance obligation, expected timing of satisfaction	1 year
SOUTHERN POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 283
Performance obligation, expected timing of satisfaction	1 year
SOUTHERN POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 277
Performance obligation, expected timing of satisfaction	1 year
SOUTHERN POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 276
Performance obligation, expected timing of satisfaction	1 year
SOUTHERN POWER CO | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation	$ 1,809
Performance obligation, expected timing of satisfaction

XML

Fair Value Measurements - Assets and Liabilities Measured at Fair Value on a Recurring Basis (Details) - USD ($) $ in Millions	Jun. 30, 2018	Dec. 31, 2017
Assets:
Fair Value	$ 33
Liabilities:
Collateral already posted, aggregate fair value	183
Fair Value, Measurements, Recurring
Assets:
Energy-related derivatives	453
Foreign currency derivatives	132
Nuclear decommissioning trusts	1,829
Cash equivalents	1,449
Other investments	10
Total	3,873
Liabilities:
Energy-related derivatives	573
Interest rate derivatives	68
Foreign currency derivatives	23
Contingent consideration	22
Total	686
Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Energy-related derivatives	287
Foreign currency derivatives	0
Nuclear decommissioning trusts	798
Cash equivalents	1,449
Other investments	9
Total	2,543
Liabilities:
Energy-related derivatives	422
Interest rate derivatives	0
Foreign currency derivatives	0
Contingent consideration	0
Total	422
Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2)
Assets:
Energy-related derivatives	166
Foreign currency derivatives	132
Nuclear decommissioning trusts	998
Cash equivalents	0
Other investments	0
Total	1,296
Liabilities:
Energy-related derivatives	151
Interest rate derivatives	68
Foreign currency derivatives	23
Contingent consideration	0
Total	242
Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3)
Assets:
Energy-related derivatives	0
Foreign currency derivatives	0
Nuclear decommissioning trusts	0
Cash equivalents	0
Other investments	1
Total	1
Liabilities:
Energy-related derivatives	0
Interest rate derivatives	0
Foreign currency derivatives	0
Contingent consideration	22
Total	22
ALABAMA POWER CO
Assets:
Energy-related derivatives	8	$ 4
Fair Value	33
Liabilities:
Energy-related derivatives	9	10
ALABAMA POWER CO | Fair Value, Measurements, Recurring
Assets:
Energy-related derivatives	8
Cash equivalents	495
Total	1,407
Liabilities:
Energy-related derivatives	9
ALABAMA POWER CO | Fair Value, Measurements, Recurring | Domestic equity
Assets:
Nuclear decommissioning trusts	526
ALABAMA POWER CO | Fair Value, Measurements, Recurring | Foreign equity
Assets:
Nuclear decommissioning trusts	116
ALABAMA POWER CO | Fair Value, Measurements, Recurring | U.S. Treasury and government agency securities
Assets:
Nuclear decommissioning trusts	18
ALABAMA POWER CO | Fair Value, Measurements, Recurring | Corporate bonds
Assets:
Nuclear decommissioning trusts	186
ALABAMA POWER CO | Fair Value, Measurements, Recurring | Mortgage and asset backed securities
Assets:
Nuclear decommissioning trusts	18
ALABAMA POWER CO | Fair Value, Measurements, Recurring | Private equity
Assets:
Nuclear decommissioning trusts	33
ALABAMA POWER CO | Fair Value, Measurements, Recurring | Other
Assets:
Nuclear decommissioning trusts	7
ALABAMA POWER CO | Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Energy-related derivatives	0
Cash equivalents	495
Total	1,031
Liabilities:
Energy-related derivatives	0
ALABAMA POWER CO | Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Domestic equity
Assets:
Nuclear decommissioning trusts	440
ALABAMA POWER CO | Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Foreign equity
Assets:
Nuclear decommissioning trusts	61
ALABAMA POWER CO | Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | U.S. Treasury and government agency securities
Assets:
Nuclear decommissioning trusts	0
ALABAMA POWER CO | Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Corporate bonds
Assets:
Nuclear decommissioning trusts	28
ALABAMA POWER CO | Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Mortgage and asset backed securities
Assets:
Nuclear decommissioning trusts	0
ALABAMA POWER CO | Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Private equity
Assets:
Nuclear decommissioning trusts	0
ALABAMA POWER CO | Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other
Assets:
Nuclear decommissioning trusts	7
ALABAMA POWER CO | Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2)
Assets:
Energy-related derivatives	8
Cash equivalents	0
Total	343
Liabilities:
Energy-related derivatives	9
ALABAMA POWER CO | Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2) | Domestic equity
Assets:
Nuclear decommissioning trusts	86
ALABAMA POWER CO | Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2) | Foreign equity
Assets:
Nuclear decommissioning trusts	55
ALABAMA POWER CO | Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2) | U.S. Treasury and government agency securities
Assets:
Nuclear decommissioning trusts	18
ALABAMA POWER CO | Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2) | Corporate bonds
Assets:
Nuclear decommissioning trusts	158
ALABAMA POWER CO | Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2) | Mortgage and asset backed securities
Assets:
Nuclear decommissioning trusts	18
ALABAMA POWER CO | Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2) | Private equity
Assets:
Nuclear decommissioning trusts	0
ALABAMA POWER CO | Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2) | Other
Assets:
Nuclear decommissioning trusts	0
ALABAMA POWER CO | Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3)
Assets:
Energy-related derivatives	0
Cash equivalents	0
Total	0
Liabilities:
Energy-related derivatives	0
ALABAMA POWER CO | Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3) | Domestic equity
Assets:
Nuclear decommissioning trusts	0
ALABAMA POWER CO | Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3) | Foreign equity
Assets:
Nuclear decommissioning trusts	0
ALABAMA POWER CO | Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3) | U.S. Treasury and government agency securities
Assets:
Nuclear decommissioning trusts	0
ALABAMA POWER CO | Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3) | Corporate bonds
Assets:
Nuclear decommissioning trusts	0
ALABAMA POWER CO | Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3) | Mortgage and asset backed securities
Assets:
Nuclear decommissioning trusts	0
ALABAMA POWER CO | Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3) | Private equity
Assets:
Nuclear decommissioning trusts	0
ALABAMA POWER CO | Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3) | Other
Assets:
Nuclear decommissioning trusts	0
GEORGIA POWER CO
Assets:
Energy-related derivatives	7	6
Nuclear decommissioning trusts	63
Liabilities:
Energy-related derivatives	25	24
GEORGIA POWER CO | Fair Value, Measurements, Recurring
Assets:
Energy-related derivatives	7
Total	931
Liabilities:
Energy-related derivatives	19
Interest rate derivatives	6
Total	25
GEORGIA POWER CO | Fair Value, Measurements, Recurring | Domestic equity
Assets:
Nuclear decommissioning trusts	243
GEORGIA POWER CO | Fair Value, Measurements, Recurring | Foreign equity
Assets:
Nuclear decommissioning trusts	135
GEORGIA POWER CO | Fair Value, Measurements, Recurring | U.S. Treasury and government agency securities
Assets:
Nuclear decommissioning trusts	239
GEORGIA POWER CO | Fair Value, Measurements, Recurring | Municipal bonds
Assets:
Nuclear decommissioning trusts	78
GEORGIA POWER CO | Fair Value, Measurements, Recurring | Corporate bonds
Assets:
Nuclear decommissioning trusts	164
GEORGIA POWER CO | Fair Value, Measurements, Recurring | Mortgage and asset backed securities
Assets:
Nuclear decommissioning trusts	41
GEORGIA POWER CO | Fair Value, Measurements, Recurring | Other
Assets:
Nuclear decommissioning trusts	24
GEORGIA POWER CO | Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Energy-related derivatives	0
Total	261
Liabilities:
Energy-related derivatives	0
Interest rate derivatives	0
Total	0
GEORGIA POWER CO | Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Domestic equity
Assets:
Nuclear decommissioning trusts	242
GEORGIA POWER CO | Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Foreign equity
Assets:
Nuclear decommissioning trusts	0
GEORGIA POWER CO | Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | U.S. Treasury and government agency securities
Assets:
Nuclear decommissioning trusts	0
GEORGIA POWER CO | Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Municipal bonds
Assets:
Nuclear decommissioning trusts	0
GEORGIA POWER CO | Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Corporate bonds
Assets:
Nuclear decommissioning trusts	0
GEORGIA POWER CO | Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Mortgage and asset backed securities
Assets:
Nuclear decommissioning trusts	0
GEORGIA POWER CO | Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other
Assets:
Nuclear decommissioning trusts	19
GEORGIA POWER CO | Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2)
Assets:
Energy-related derivatives	7
Total	670
Liabilities:
Energy-related derivatives	19
Interest rate derivatives	6
Total	25
GEORGIA POWER CO | Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2) | Domestic equity
Assets:
Nuclear decommissioning trusts	1
GEORGIA POWER CO | Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2) | Foreign equity
Assets:
Nuclear decommissioning trusts	135
GEORGIA POWER CO | Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2) | U.S. Treasury and government agency securities
Assets:
Nuclear decommissioning trusts	239
GEORGIA POWER CO | Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2) | Municipal bonds
Assets:
Nuclear decommissioning trusts	78
GEORGIA POWER CO | Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2) | Corporate bonds
Assets:
Nuclear decommissioning trusts	164
GEORGIA POWER CO | Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2) | Mortgage and asset backed securities
Assets:
Nuclear decommissioning trusts	41
GEORGIA POWER CO | Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2) | Other
Assets:
Nuclear decommissioning trusts	5
GEORGIA POWER CO | Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3)
Assets:
Energy-related derivatives	0
Total	0
Liabilities:
Energy-related derivatives	0
Interest rate derivatives	0
Total	0
GEORGIA POWER CO | Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3) | Domestic equity
Assets:
Nuclear decommissioning trusts	0
GEORGIA POWER CO | Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3) | Foreign equity
Assets:
Nuclear decommissioning trusts	0
GEORGIA POWER CO | Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3) | U.S. Treasury and government agency securities
Assets:
Nuclear decommissioning trusts	0
GEORGIA POWER CO | Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3) | Municipal bonds
Assets:
Nuclear decommissioning trusts	0
GEORGIA POWER CO | Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3) | Corporate bonds
Assets:
Nuclear decommissioning trusts	0
GEORGIA POWER CO | Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3) | Mortgage and asset backed securities
Assets:
Nuclear decommissioning trusts	0
GEORGIA POWER CO | Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3) | Other
Assets:
Nuclear decommissioning trusts	0
GULF POWER CO
Assets:
Energy-related derivatives	0	0
Liabilities:
Energy-related derivatives	12	21
GULF POWER CO | Fair Value, Measurements, Recurring
Assets:
Cash equivalents	27
Liabilities:
Energy-related derivatives	12
GULF POWER CO | Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Cash equivalents	27
Liabilities:
Energy-related derivatives	0
GULF POWER CO | Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2)
Assets:
Cash equivalents	0
Liabilities:
Energy-related derivatives	12
GULF POWER CO | Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3)
Assets:
Cash equivalents	0
Liabilities:
Energy-related derivatives	0
MISSISSIPPI POWER CO
Assets:
Energy-related derivatives	3	3
Liabilities:
Energy-related derivatives	9	9
MISSISSIPPI POWER CO | Fair Value, Measurements, Recurring
Assets:
Energy-related derivatives	3
Cash equivalents	205
Total	208
Liabilities:
Energy-related derivatives	9
MISSISSIPPI POWER CO | Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Energy-related derivatives	0
Cash equivalents	205
Total	205
Liabilities:
Energy-related derivatives	0
MISSISSIPPI POWER CO | Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2)
Assets:
Energy-related derivatives	3
Cash equivalents	0
Total	3
Liabilities:
Energy-related derivatives	9
MISSISSIPPI POWER CO | Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3)
Assets:
Energy-related derivatives	0
Cash equivalents	0
Total	0
Liabilities:
Energy-related derivatives	0
SOUTHERN POWER CO
Assets:
Energy-related derivatives	135	132
Liabilities:
Energy-related derivatives	26	36
SOUTHERN POWER CO | Fair Value, Measurements, Recurring
Assets:
Energy-related derivatives	3
Foreign currency derivatives	132
Total	135
Liabilities:
Energy-related derivatives	3
Foreign currency derivatives	23
Contingent consideration	22
Total	48
SOUTHERN POWER CO | Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Energy-related derivatives	0
Foreign currency derivatives	0
Total	0
Liabilities:
Energy-related derivatives	0
Foreign currency derivatives	0
Contingent consideration	0
Total	0
SOUTHERN POWER CO | Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2)
Assets:
Energy-related derivatives	3
Foreign currency derivatives	132
Total	135
Liabilities:
Energy-related derivatives	3
Foreign currency derivatives	23
Contingent consideration	0
Total	26
SOUTHERN POWER CO | Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3)
Assets:
Energy-related derivatives	0
Foreign currency derivatives	0
Total	0
Liabilities:
Energy-related derivatives	0
Foreign currency derivatives	0
Contingent consideration	22
Total	22
SOUTHERN Co GAS
Assets:
Energy-related derivatives	431	554
Liabilities:
Energy-related derivatives	521	660
Collateral already posted, aggregate fair value	183	$ 193
SOUTHERN Co GAS | Fair Value, Measurements, Recurring
Assets:
Energy-related derivatives	431
Cash equivalents	1
Total	432
Liabilities:
Energy-related derivatives	521
SOUTHERN Co GAS | Fair Value, Measurements, Recurring | Quoted Prices in Active Markets for Identical Assets (Level 1)
Assets:
Energy-related derivatives	287
Cash equivalents	1
Total	288
Liabilities:
Energy-related derivatives	422
SOUTHERN Co GAS | Fair Value, Measurements, Recurring | Significant Other Observable Inputs (Level 2)
Assets:
Energy-related derivatives	144
Cash equivalents	0
Total	144
Liabilities:
Energy-related derivatives	99
SOUTHERN Co GAS | Fair Value, Measurements, Recurring | Significant Unobservable Inputs (Level 3)
Assets:
Energy-related derivatives	0
Cash equivalents	0
Total	0
Liabilities:
Energy-related derivatives	0
Nuclear Decommissioning Trusts
Assets:
Fair Value	33
Nuclear Decommissioning Trusts | ALABAMA POWER CO
Assets:
Fair Value	33
Weather Derivative | Fair Value, Measurements, Recurring
Assets:
Energy-related derivatives	$ 3

XML

Fair Value Measurements - Narrative (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Fair Value, Option, Quantitative Disclosures [Line Items]
Increase (decrease) in fair value of funds	$ 14	$ 55	$ 4	$ 118
Private equity
Fair Value, Option, Quantitative Disclosures [Line Items]
Liquidations term			10 years
ALABAMA POWER CO
Fair Value, Option, Quantitative Disclosures [Line Items]
Increase (decrease) in fair value of funds	15	28	$ 10	62
GEORGIA POWER CO
Fair Value, Option, Quantitative Disclosures [Line Items]
Increase (decrease) in fair value of funds	$ (1)	$ 27	$ (6)	$ 56

XML

Fair Value Measurements - Fair Value Measurements Of Investments Calculated At Net Asset Value Per Share (Details) $ in Millions	Jun. 30, 2018 USD ($)
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Fair Value	$ 33
Private equity
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Fair Value	33
Unfunded Commitments	33
ALABAMA POWER CO
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Fair Value	33
ALABAMA POWER CO | Private equity
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Fair Value	33
Unfunded Commitments	$ 33

XML

Fair Value Measurements - Financial Instruments for which Carrying Amount did not Equal Fair Value (Details) $ in Millions	Jun. 30, 2018 USD ($)
Southern Company
Long-term debt, including securities due within one year:
Carrying Amount	$ 45,806
Fair Value	46,481
ALABAMA POWER CO
Long-term debt, including securities due within one year:
Carrying Amount	8,119
Fair Value	8,435
GEORGIA POWER CO
Long-term debt, including securities due within one year:
Carrying Amount	10,294
Fair Value	10,499
GULF POWER CO
Long-term debt, including securities due within one year:
Carrying Amount	1,285
Fair Value	1,311
MISSISSIPPI POWER CO
Long-term debt, including securities due within one year:
Carrying Amount	1,779
Fair Value	1,760
SOUTHERN POWER CO
Long-term debt, including securities due within one year:
Carrying Amount	5,037
Fair Value	5,094
SOUTHERN Co GAS
Long-term debt, including securities due within one year:
Carrying Amount	5,823
Fair Value	$ 5,957

XML

Stockholders' Equity - Earnings per Share (Details) - shares shares in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Equity [Abstract]
As reported shares (in shares)	1,014.0	998.0	1,012.0	996.0
Effect of stock-based compensation (in shares)	0.0	7.0	5.0	7.0
Diluted shares (in shares)	1,014.0	1,005.0	1,017.0	1,003.0
Stock options and performance share award units that were not included in the diluted earnings per share calculation (in shares)	5.3	0.0	0.0	0.0

XML

Stockholders' Equity - Changes in Stockholders' Equity (Details) - USD ($) shares in Thousands, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Changes in Stockholders' Equity
Beginning balance, treasury shares (in shares)			(900)
Beginning balance			$ 25,528	$ 26,612
Consolidated net income attributable to Southern Company	$ (154)	$ (1,381)	784	(723)
Other comprehensive income			41	(11)
Stock issued			222	417
Stock-based compensation			48	72
Cash dividends on common stock			(1,194)	(1,134)
Preference stock redemption				(150)
Contributions from noncontrolling interests			31	71
Distributions to noncontrolling interests			(42)	(40)
Net income attributable to noncontrolling interests			17	16
Sale of SPSH noncontrolling interests			1,283
Reclassification from redeemable noncontrolling interests				114
Other			$ (26)	(3)
Ending balance, treasury shares (in shares)	(1,000)		(1,000)
Ending balance	$ 26,692	$ 25,241	$ 26,692	$ 25,241
Number of Common Shares Issued
Changes in Stockholders' Equity
Beginning balance (in shares)			1,008,532	991,213
Stock issued (in shares)			6,590	9,129
Other (in shares)			0
Ending balance (in shares)	1,015,122	1,000,342	1,015,122	1,000,342
Number of Common Shares Treasury Issued
Changes in Stockholders' Equity
Beginning balance, treasury shares (in shares)			(929)	(819)
Stock issued (in shares)			0	0
Other (in shares)			(57)	(49)
Ending balance, treasury shares (in shares)	(986)	(868)	(986)	(868)
Common Stockholders' Equity
Changes in Stockholders' Equity
Beginning balance			$ 24,167	$ 24,758
Consolidated net income attributable to Southern Company			784	(723)
Other comprehensive income			41	(11)
Stock issued			222	417
Stock-based compensation			48	72
Cash dividends on common stock			(1,194)	(1,134)
Sale of SPSH noncontrolling interests			(407)
Other			(25)	(7)
Ending balance	$ 23,636	$ 23,372	23,636	23,372
Preferred and Preference Stock of Subsidiaries
Changes in Stockholders' Equity
Beginning balance			0	609
Preference stock redemption				(150)
Other			0	3
Ending balance	0	462	0	462
Noncontrolling Interest
Changes in Stockholders' Equity
Beginning balance			1,361	1,245
Contributions from noncontrolling interests			31	71
Distributions to noncontrolling interests			(42)	(40)
Net income attributable to noncontrolling interests			17	16
Sale of SPSH noncontrolling interests			1,690
Reclassification from redeemable noncontrolling interests				114
Other			(1)	1
Ending balance	$ 3,056	$ 1,407	$ 3,056	$ 1,407

XML

Financing - Narrative (Details)			1 Months Ended				3 Months Ended	6 Months Ended
	Aug. 07, 2018 USD ($)	May 20, 2018	Jun. 30, 2018 USD ($) agreement	May 31, 2018 USD ($) agreement	Apr. 30, 2018 USD ($)	Mar. 31, 2018 USD ($)	Jun. 30, 2018 USD ($)	Jun. 30, 2018 USD ($)	Jan. 31, 2018 USD ($)	Jan. 04, 2018 USD ($)	Sep. 30, 2017 USD ($)
Debt Instrument [Line Items]
Variable rate pollution control revenue bonds outstanding			$ 1,500,000,000				$ 1,500,000,000	$ 1,500,000,000
Maximum borrowing capacity			8,143,000,000				8,143,000,000	8,143,000,000
Floating rate Promissory Note Due July 2018
Debt Instrument [Line Items]
Debt face amount										$ 100,000,000
Southern Company
Debt Instrument [Line Items]
Maximum borrowing capacity			$ 2,000,000,000				2,000,000,000	2,000,000,000
Southern Company | Floating Rate Bank Term Loan Agreement 1 | Notes Payable to Banks
Debt Instrument [Line Items]
Debt face amount						$ 900,000,000
Southern Company | Uncommitted Bank Credit Arrangement | Notes Payable to Banks
Debt Instrument [Line Items]
Debt face amount					$ 250,000,000
Debt instrument, payable by demand from bank, term					30 days
Southern Company | Notes Payable to Banks | Floating Rate Bank Term Loan Agreement 1
Debt Instrument [Line Items]
Number of loan agreements | agreement			2
Southern Company | Notes Payable to Banks | Floating Rate Bank Term Loan Agreement 4
Debt Instrument [Line Items]
Debt face amount			$ 100,000,000				100,000,000	100,000,000
Southern Company | Notes Payable to Banks | Floating Rate Bank Term Loan Agreement 5
Debt Instrument [Line Items]
Debt face amount			100,000,000				100,000,000	100,000,000
ALABAMA POWER CO
Debt Instrument [Line Items]
Variable rate pollution control revenue bonds outstanding			854,000,000				854,000,000	854,000,000
Fixed rate pollution control revenue bonds outstanding			120,000,000				120,000,000	120,000,000
Maximum borrowing capacity			1,333,000,000				1,333,000,000	1,333,000,000
ALABAMA POWER CO | Senior Notes | Series 2018A Floating Rate Senior Notes
Debt Instrument [Line Items]
Debt face amount			$ 500,000,000				$ 500,000,000	$ 500,000,000
Debt stated interest rate			4.30%				4.30%	4.30%
ALABAMA POWER CO | Senior Notes | Series 2008B 5.40% Senior Notes due June 1, 2018
Debt Instrument [Line Items]
Debt stated interest rate					5.40%
Repurchased face amount					$ 250,000,000
GEORGIA POWER CO
Debt Instrument [Line Items]
Variable rate pollution control revenue bonds outstanding			$ 550,000,000				$ 550,000,000	$ 550,000,000
Fixed rate pollution control revenue bonds outstanding			232,000,000				232,000,000	232,000,000
Maximum borrowing capacity			1,750,000,000				1,750,000,000	$ 1,750,000,000
Amortization period for line of credit facility								5 years
Percent of eligible project costs to be reimbursed								70.00%
GEORGIA POWER CO | Loan Guarantee Agreement
Debt Instrument [Line Items]
Conditional borrowing commitment											$ 1,670,000,000
GEORGIA POWER CO | Notes Payable to Banks | Floating Rate Bank Term Loan Agreement 2
Debt Instrument [Line Items]
Debt face amount									$ 150,000,000
GEORGIA POWER CO | Notes Payable to Banks | Floating Rate Bank Term Loan Agreement 3
Debt Instrument [Line Items]
Debt face amount									$ 100,000,000
GEORGIA POWER CO | Senior Notes
Debt Instrument [Line Items]
Repayments of debt				$ 902,000,000
GEORGIA POWER CO | Senior Notes | Series 2007A 5.65% Senior Notes
Debt Instrument [Line Items]
Debt instrument, repurchase amount				89,000,000
Debt face amount				$ 250,000,000
Debt stated interest rate				5.65%
GEORGIA POWER CO | Senior Notes | Series 2009A 5.95% Senior Notes
Debt Instrument [Line Items]
Debt instrument, repurchase amount				$ 326,000,000
Debt face amount				$ 500,000,000
Debt stated interest rate				5.95%
GEORGIA POWER CO | Senior Notes | Series 2010B 5.40% Senior Notes
Debt Instrument [Line Items]
Debt instrument, repurchase amount				$ 335,000,000
Debt face amount				$ 600,000,000
Debt stated interest rate				5.40%
GEORGIA POWER CO | Municipal Bonds | Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Fifth Series 1995
Debt Instrument [Line Items]
Debt face amount						104,600,000.0
GEORGIA POWER CO | Municipal Bonds | Development Authority of Bartow County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Bowen Project), First Series 1997
Debt Instrument [Line Items]
Debt face amount						173,000,000
GEORGIA POWER CO | Municipal Bonds | Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Fifth Series 1994
Debt Instrument [Line Items]
Debt face amount					$ 55,000,000
GEORGIA POWER CO | Municipal Bonds | Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Second Series 2008
Debt Instrument [Line Items]
Debt face amount			65,000,000				65,000,000	$ 65,000,000
GULF POWER CO
Debt Instrument [Line Items]
Variable rate pollution control revenue bonds outstanding			82,000,000				82,000,000	82,000,000
Fixed rate pollution control revenue bonds outstanding			37,000,000				37,000,000	37,000,000
Maximum borrowing capacity			280,000,000				280,000,000	280,000,000
MISSISSIPPI POWER CO
Debt Instrument [Line Items]
Variable rate pollution control revenue bonds outstanding			40,000,000				40,000,000	40,000,000
Fixed rate pollution control revenue bonds outstanding			93,000,000				93,000,000	93,000,000
Maximum borrowing capacity			100,000,000				100,000,000	100,000,000
MISSISSIPPI POWER CO | Notes Payable to Banks
Debt Instrument [Line Items]
Debt face amount						300,000,000
MISSISSIPPI POWER CO | Senior Notes | Series 2018A Floating Rate Senior Notes
Debt Instrument [Line Items]
Debt face amount						300,000,000
MISSISSIPPI POWER CO | Senior Notes | Series 2018B 3.95% Senior Notes
Debt Instrument [Line Items]
Debt face amount						$ 300,000,000
Debt stated interest rate						3.95%
MISSISSIPPI POWER CO | Promissory Notes | Promissory Notes
Debt Instrument [Line Items]
Repayments of debt							200,000,000
MISSISSIPPI POWER CO | Unsecured Debt | Unsecured Term Loan
Debt Instrument [Line Items]
Repayments of debt						$ 900,000,000
Traditional Electric Operating Companies
Debt Instrument [Line Items]
Fixed rate pollution control revenue bonds outstanding			482,000,000				482,000,000	482,000,000
SOUTHERN POWER CO
Debt Instrument [Line Items]
Repayments of debt				$ 770,000,000
Maximum borrowing capacity			750,000,000				750,000,000	750,000,000
SOUTHERN POWER CO | Floating Rate Bank Term Loan Agreement 1 | Notes Payable to Banks
Debt Instrument [Line Items]
Debt face amount				$ 100,000,000
Number of loan agreements | agreement				2
Repurchased face amount			$ 420,000,000				$ 420,000,000	$ 420,000,000
SOUTHERN POWER CO | Senior Notes | Series 2015A 1.50% Senior Notes
Debt Instrument [Line Items]
Debt stated interest rate			1.50%				1.50%	1.50%
Repurchased face amount			$ 350,000,000				$ 350,000,000	$ 350,000,000
SOUTHERN Co GAS
Debt Instrument [Line Items]
Maximum borrowing capacity			1,900,000,000				1,900,000,000	1,900,000,000
SOUTHERN Co GAS | Uncommitted Bank Credit Arrangement | Notes Payable to Banks
Debt Instrument [Line Items]
Debt face amount				$ 95,000,000
Debt instrument, payable by demand from bank, term				30 days
SOUTHERN Co GAS | Senior Notes | Series 2017A
Debt Instrument [Line Items]
Debt face amount			200,000,000				200,000,000	200,000,000
Nicor Gas
Debt Instrument [Line Items]
Maximum borrowing capacity			500,000,000				500,000,000	500,000,000
Nicor Gas | Collateralized Mortgage Backed Securities | First Mortgage Bonds
Debt Instrument [Line Items]
Debt face amount			181,000,000				$ 181,000,000	181,000,000
Subsequent Event | MISSISSIPPI POWER CO | Municipal Bonds | Pollution Control Revenue Bonds
Debt Instrument [Line Items]
Debt instrument, repurchase amount	$ 43,000,000
Subsequent Event | MISSISSIPPI POWER CO | Promissory Notes | Promissory Notes
Debt Instrument [Line Items]
Repayments of debt	$ 50,000,000
SP Solar Holdings I, LP | SOUTHERN POWER CO
Debt Instrument [Line Items]
Limited liability company or limited partnership, members or limited partners, ownership interest		33.00%		33.00%			33.00%
FFB Loan | GEORGIA POWER CO
Debt Instrument [Line Items]
Maximum borrowing capacity			$ 2,600,000,000				$ 2,600,000,000	$ 2,600,000,000
Conditional borrowing commitment											$ 1,670,000,000

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Financing - Schedule of Credit Arrangements (Details)	Jun. 30, 2018 USD ($)
Line of Credit Facility [Line Items]
Expires, 2018	$ 122,000,000
Expires, 2019	86,000,000
Expires, 2020	735,000,000
Expires, 2022	7,200,000,000
Total	8,143,000,000
Unused	8,101,000,000
Executable Term Loans, One Year	45,000,000
Expires Within One Year, Term Out	45,000,000
Expires Within One Year, No Term Out	163,000,000
Southern Company
Line of Credit Facility [Line Items]
Expires, 2018	0
Expires, 2019	0
Expires, 2020	0
Expires, 2022	2,000,000,000
Total	2,000,000,000
Unused	1,999,000,000
Executable Term Loans, One Year	0
Expires Within One Year, Term Out	0
Expires Within One Year, No Term Out	0
ALABAMA POWER CO
Line of Credit Facility [Line Items]
Expires, 2018	2,000,000
Expires, 2019	31,000,000
Expires, 2020	500,000,000
Expires, 2022	800,000,000
Total	1,333,000,000
Unused	1,333,000,000
Executable Term Loans, One Year	0
Expires Within One Year, Term Out	0
Expires Within One Year, No Term Out	33,000,000
GEORGIA POWER CO
Line of Credit Facility [Line Items]
Expires, 2018	0
Expires, 2019	0
Expires, 2020	0
Expires, 2022	1,750,000,000
Total	1,750,000,000
Unused	1,736,000,000
Executable Term Loans, One Year	0
Expires Within One Year, Term Out	0
Expires Within One Year, No Term Out	0
GULF POWER CO
Line of Credit Facility [Line Items]
Expires, 2018	20,000,000
Expires, 2019	25,000,000
Expires, 2020	235,000,000
Expires, 2022	0
Total	280,000,000
Unused	280,000,000
Executable Term Loans, One Year	45,000,000
Expires Within One Year, Term Out	45,000,000
Expires Within One Year, No Term Out	0
MISSISSIPPI POWER CO
Line of Credit Facility [Line Items]
Expires, 2018	100,000,000
Expires, 2019	0
Expires, 2020	0
Expires, 2022	0
Total	100,000,000
Unused	100,000,000
Executable Term Loans, One Year	0
Expires Within One Year, Term Out	0
Expires Within One Year, No Term Out	100,000,000
SOUTHERN POWER CO
Line of Credit Facility [Line Items]
Expires, 2018	0
Expires, 2019	0
Expires, 2020	0
Expires, 2022	750,000,000
Total	750,000,000
Unused	728,000,000
Executable Term Loans, One Year	0
Expires Within One Year, Term Out	0
Expires Within One Year, No Term Out	0
SOUTHERN Co GAS
Line of Credit Facility [Line Items]
Expires, 2018	0
Expires, 2019	0
Expires, 2020	0
Expires, 2022	1,900,000,000
Total	1,900,000,000
Unused	1,895,000,000
Executable Term Loans, One Year	0
Expires Within One Year, Term Out	0
Expires Within One Year, No Term Out	0
Other
Line of Credit Facility [Line Items]
Expires, 2018	0
Expires, 2019	30,000,000
Expires, 2020	0
Expires, 2022	0
Total	30,000,000
Unused	30,000,000
Executable Term Loans, One Year	0
Expires Within One Year, Term Out	0
Expires Within One Year, No Term Out	30,000,000
Southern Company Gas Capital
Line of Credit Facility [Line Items]
Total	1,400,000,000.0
Nicor Gas
Line of Credit Facility [Line Items]
Total	500,000,000
Standby Letters of Credit | SOUTHERN POWER CO
Line of Credit Facility [Line Items]
Total	120,000,000
Unused	$ 23,000,000

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Financing - Schedule of Long-Term Debt Financing Activities (Details) $ in Millions	6 Months Ended
	Jun. 30, 2018 USD ($)
Debt Instrument [Line Items]
Senior Note Issuances	$ 1,100
Senior Note Maturities, Redemptions, and Repurchases	1,350
Revenue Bond Maturities, Redemptions, and Repurchases	598
Other Long-Term Debt Redemptions and Maturities	1,431
ALABAMA POWER CO
Debt Instrument [Line Items]
Senior Note Issuances	500
Senior Note Maturities, Redemptions, and Repurchases	0
Revenue Bond Maturities, Redemptions, and Repurchases	0
Other Long-Term Debt Redemptions and Maturities	0
GEORGIA POWER CO
Debt Instrument [Line Items]
Senior Note Issuances	0
Senior Note Maturities, Redemptions, and Repurchases	1,000
Revenue Bond Maturities, Redemptions, and Repurchases	398
Other Long-Term Debt Redemptions and Maturities	104
MISSISSIPPI POWER CO
Debt Instrument [Line Items]
Senior Note Issuances	600
Senior Note Maturities, Redemptions, and Repurchases	0
Revenue Bond Maturities, Redemptions, and Repurchases	0
Other Long-Term Debt Redemptions and Maturities	900
SOUTHERN POWER CO
Debt Instrument [Line Items]
Senior Note Issuances	0
Senior Note Maturities, Redemptions, and Repurchases	350
Revenue Bond Maturities, Redemptions, and Repurchases	0
Other Long-Term Debt Redemptions and Maturities	420
SOUTHERN Co GAS
Debt Instrument [Line Items]
Senior Note Issuances	0
Senior Note Maturities, Redemptions, and Repurchases	0
Revenue Bond Maturities, Redemptions, and Repurchases	200
Other Long-Term Debt Redemptions and Maturities	0
Other
Debt Instrument [Line Items]
Senior Note Issuances	0
Senior Note Maturities, Redemptions, and Repurchases	0
Revenue Bond Maturities, Redemptions, and Repurchases	0
Other Long-Term Debt Redemptions and Maturities	$ 7

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Retirement Benefits (Details) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Amortization:
Net (gain)/loss
Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, expected future employer contributions, remainder of fiscal year	$ 0		$ 0
Pension Plans | ALABAMA POWER CO
Pension Plans and Postretirement Plans
Service cost	20,000,000	16,000,000	39,000,000	$ 32,000,000
Interest cost	25,000,000	24,000,000	50,000,000	48,000,000
Expected return on plan assets	(53,000,000)	(49,000,000)	(104,000,000)	(98,000,000)
Amortization:
Prior service costs	1,000,000	0	1,000,000	1,000,000
Regulatory asset	0		0
Net (gain)/loss	13,000,000	11,000,000	27,000,000	21,000,000
Net periodic pension cost (income)	6,000,000	2,000,000	13,000,000	4,000,000
Pension Plans | GEORGIA POWER CO
Pension Plans and Postretirement Plans
Service cost	21,000,000	18,000,000	43,000,000	37,000,000
Interest cost	35,000,000	35,000,000	70,000,000	69,000,000
Expected return on plan assets	(74,000,000)	(70,000,000)	(148,000,000)	(141,000,000)
Amortization:
Prior service costs	1,000,000	1,000,000	1,000,000	2,000,000
Regulatory asset	0		0
Net (gain)/loss	17,000,000	14,000,000	34,000,000	28,000,000
Net periodic pension cost (income)	0	(2,000,000)	0	(5,000,000)
Pension Plans | GULF POWER CO
Pension Plans and Postretirement Plans
Service cost	4,000,000	4,000,000	8,000,000	7,000,000
Interest cost	5,000,000	5,000,000	10,000,000	10,000,000
Expected return on plan assets	(10,000,000)	(9,000,000)	(20,000,000)	(19,000,000)
Amortization:
Prior service costs	0	0	0	0
Regulatory asset	0		0
Net (gain)/loss	3,000,000	1,000,000	5,000,000	3,000,000
Net periodic pension cost (income)	2,000,000	1,000,000	3,000,000	1,000,000
Pension Plans | MISSISSIPPI POWER CO
Pension Plans and Postretirement Plans
Service cost	4,000,000	3,000,000	8,000,000	7,000,000
Interest cost	5,000,000	5,000,000	10,000,000	10,000,000
Expected return on plan assets	(10,000,000)	(10,000,000)	(20,000,000)	(20,000,000)
Amortization:
Prior service costs	0	1,000,000	0	1,000,000
Regulatory asset	0		0
Net (gain)/loss	2,000,000	2,000,000	5,000,000	4,000,000
Net periodic pension cost (income)	1,000,000	1,000,000	3,000,000	2,000,000
Pension Plans | SOUTHERN POWER CO
Pension Plans and Postretirement Plans
Service cost	2,000,000		4,000,000
Interest cost	2,000,000		3,000,000
Expected return on plan assets	(2,000,000)		(5,000,000)
Amortization:
Prior service costs	0		0
Regulatory asset	0		0
Net (gain)/loss	0		1,000,000
Net periodic pension cost (income)	2,000,000		3,000,000
Pension Plans | SOUTHERN Co GAS
Pension Plans and Postretirement Plans
Service cost	8,000,000	5,000,000	16,000,000	11,000,000
Interest cost	9,000,000	10,000,000	19,000,000	20,000,000
Expected return on plan assets	(17,000,000)	(17,000,000)	(35,000,000)	(35,000,000)
Amortization:
Prior service costs	0	(1,000,000)	(1,000,000)	(1,000,000)
Regulatory asset	4,000,000		7,000,000
Net (gain)/loss	3,000,000	5,000,000	6,000,000	10,000,000
Net periodic pension cost (income)	7,000,000	2,000,000	12,000,000	5,000,000
Pension Plans | Southern Company
Pension Plans and Postretirement Plans
Service cost	89,000,000	74,000,000	179,000,000	147,000,000
Interest cost	116,000,000	113,000,000	232,000,000	227,000,000
Expected return on plan assets	(235,000,000)	(225,000,000)	(471,000,000)	(449,000,000)
Amortization:
Prior service costs	1,000,000	3,000,000	2,000,000	6,000,000
Regulatory asset	0		0
Net (gain)/loss	54,000,000	41,000,000	107,000,000	81,000,000
Net periodic pension cost (income)	25,000,000	6,000,000	49,000,000	12,000,000
Postretirement Benefits | ALABAMA POWER CO
Pension Plans and Postretirement Plans
Service cost	2,000,000	2,000,000	3,000,000	3,000,000
Interest cost	4,000,000	4,000,000	8,000,000	9,000,000
Expected return on plan assets	(7,000,000)	(8,000,000)	(13,000,000)	(14,000,000)
Amortization:
Prior service costs	1,000,000	1,000,000		2,000,000
Regulatory asset	0		2,000,000
Net (gain)/loss	1,000,000	1,000,000	1,000,000	1,000,000
Net periodic pension cost (income)	1,000,000	0	1,000,000	1,000,000
Postretirement Benefits | GEORGIA POWER CO
Pension Plans and Postretirement Plans
Service cost	1,000,000	1,000,000	3,000,000	3,000,000
Interest cost	7,000,000	8,000,000	14,000,000	15,000,000
Expected return on plan assets	(7,000,000)	(6,000,000)	(13,000,000)	(12,000,000)
Amortization:
Prior service costs	1,000,000	1,000,000		1,000,000
Regulatory asset	0		1,000,000
Net (gain)/loss	2,000,000	1,000,000	4,000,000	3,000,000
Net periodic pension cost (income)	4,000,000	5,000,000	9,000,000	10,000,000
Postretirement Benefits | GULF POWER CO
Pension Plans and Postretirement Plans
Service cost	1,000,000	1,000,000	1,000,000	1,000,000
Interest cost	0	0	1,000,000	1,000,000
Expected return on plan assets	(1,000,000)	(1,000,000)	(1,000,000)	(1,000,000)
Amortization:
Prior service costs	0	0		0
Regulatory asset	0		0
Net (gain)/loss	0	0	0	0
Net periodic pension cost (income)	0	0	1,000,000	1,000,000
Postretirement Benefits | MISSISSIPPI POWER CO
Pension Plans and Postretirement Plans
Service cost	1,000,000	1,000,000	1,000,000	1,000,000
Interest cost	1,000,000	1,000,000	2,000,000	2,000,000
Expected return on plan assets	(1,000,000)	(1,000,000)	(1,000,000)	(1,000,000)
Amortization:
Prior service costs	0	0		0
Regulatory asset	0		0
Net (gain)/loss	0	0	0	0
Net periodic pension cost (income)	1,000,000	1,000,000	2,000,000	2,000,000
Postretirement Benefits | SOUTHERN POWER CO
Pension Plans and Postretirement Plans
Service cost	0		0
Interest cost	0		0
Expected return on plan assets	0		0
Amortization:
Prior service costs	0
Regulatory asset	0		0
Net (gain)/loss	0		0
Net periodic pension cost (income)	0		0
Postretirement Benefits | SOUTHERN Co GAS
Pension Plans and Postretirement Plans
Service cost	0	0	1,000,000	1,000,000
Interest cost	3,000,000	2,000,000	5,000,000	5,000,000
Expected return on plan assets	(2,000,000)	(1,000,000)	(4,000,000)	(3,000,000)
Amortization:
Prior service costs	0	0		(1,000,000)
Regulatory asset	2,000,000		3,000,000
Net (gain)/loss	0	1,000,000	0	2,000,000
Net periodic pension cost (income)	3,000,000	2,000,000	5,000,000	4,000,000
Postretirement Benefits | Southern Company
Pension Plans and Postretirement Plans
Service cost	6,000,000	6,000,000	12,000,000	12,000,000
Interest cost	18,000,000	20,000,000	37,000,000	40,000,000
Expected return on plan assets	(17,000,000)	(17,000,000)	(34,000,000)	(33,000,000)
Amortization:
Prior service costs	1,000,000	1,000,000		3,000,000
Regulatory asset	0		3,000,000
Net (gain)/loss	4,000,000	5,000,000	7,000,000	7,000,000
Net periodic pension cost (income)	$ 12,000,000	$ 15,000,000	$ 25,000,000	$ 29,000,000

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Income Taxes (Details)	1 Months Ended		3 Months Ended				6 Months Ended
	Apr. 30, 2018 USD ($)	Mar. 31, 2018 USD ($)	Dec. 31, 2018 operating_facility	Sep. 30, 2018 USD ($)	Jun. 30, 2018 USD ($) operating_facility	Jun. 30, 2017 USD ($)	Jun. 30, 2018 USD ($) operating_facility	Jun. 30, 2017 USD ($)	Dec. 31, 2017 USD ($)
Income Tax Contingency [Line Items]
Effective tax rate							(3.20%)	(28.60%)
Increase in effective tax rate due to loss on Kemper IGCC							$ 3,100,000,000
Income taxes (benefit)					$ (139,000,000)	$ (587,000,000)	(25,000,000)	$ (273,000,000)
Unrecognized tax benefits					0		$ 0
Significantly increase (decrease) in amount of unrecognized tax benefits							12 months
ALABAMA POWER CO
Income Tax Contingency [Line Items]
Effective tax rate							22.80%	40.20%
Income taxes (benefit)					64,000,000	151,000,000	$ 145,000,000	$ 277,000,000
GEORGIA POWER CO
Income Tax Contingency [Line Items]
Effective tax rate							(53.50%)	36.60%
Income taxes (benefit)					(143,000,000)	199,000,000	$ (50,000,000)	$ 355,000,000
GEORGIA POWER CO | Plant Vogtle Units 3 And 4
Income Tax Contingency [Line Items]
Estimated project costs							$ 1,100,000,000
GULF POWER CO
Income Tax Contingency [Line Items]
Effective tax rate							3.30%	39.80%
Income taxes (benefit)					(11,000,000)	24,000,000	$ 3,000,000	$ 38,000,000
MISSISSIPPI POWER CO
Income Tax Contingency [Line Items]
Effective tax rate							18.70%	(30.50%)
Increase in effective tax rate due to loss on Kemper IGCC							$ 3,100,000,000
Income taxes (benefit)					13,000,000	(881,000,000)	$ 9,000,000	$ (908,000,000)
SOUTHERN Co GAS
Income Tax Contingency [Line Items]
Effective tax rate							39.10%	38.50%
Income taxes (benefit)					55,000,000	31,000,000	$ 159,000,000	$ 180,000,000
SOUTHERN POWER CO
Income Tax Contingency [Line Items]
Effective tax rate							(1386.50%)	(114.70%)
Income taxes (benefit)	$ (4,000,000)	$ (50,000,000)			(73,000,000)	$ (38,000,000)	$ (172,000,000)	$ (90,000,000)
SOUTHERN POWER CO | Florida Plants | Disposal Group, Held-for-sale, Not Discontinued Operations
Income Tax Contingency [Line Items]
Pre-tax impairment charge					$ 119,000,000		$ 119,000,000
Number of natural gas-fired operating facilities disposed | operating_facility					2		2
Investment Tax Credit Carryforward
Income Tax Contingency [Line Items]
Tax credit carryforward, amount					$ 2,300,000,000		$ 2,300,000,000		$ 2,100,000,000
Scenario, Forecast | SOUTHERN POWER CO
Income Tax Contingency [Line Items]
Income taxes (benefit)				$ (10,000,000)
Number of operating wind facilities | operating_facility			8

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Derivatives - Energy-Related and Interest Rate Derivatives (Details) MMBTU in Millions	6 Months Ended
	Jun. 30, 2018 USD ($) MMBTU
Interest rate derivatives
Interest rate derivatives
Notional Amount	$ 2,500,000,000
Fair Value Gain (Loss) at June 30, 2018	$ (69,000,000)
Southern Company | Energy-related, Natural Gas
Energy-related derivative contracts
Net Purchased mmBtu | MMBTU	701
Longest Hedge Date	2022
Longest Non-Hedge Date	2029
Southern Company | Interest rate derivatives | 2020-06-15 | Fair Value Hedges of Existing Debt
Interest rate derivatives
Notional Amount	$ 300,000,000
Interest Rate Received	2.75%
Fair Value Gain (Loss) at June 30, 2018	$ (6,000,000)
Southern Company | Interest rate derivatives | 2020-06-15 | London Interbank Offered Rate (LIBOR) | Fair Value Hedges of Existing Debt
Interest rate derivatives
Weighted Average Interest Rate Paid	0.92%
Southern Company | Interest rate derivatives | 7/1/2021 | Fair Value Hedges of Existing Debt
Interest rate derivatives
Notional Amount	$ 1,500,000,000
Interest Rate Received	2.35%
Fair Value Gain (Loss) at June 30, 2018	$ (57,000,000)
Southern Company | Interest rate derivatives | 7/1/2021 | London Interbank Offered Rate (LIBOR) | Fair Value Hedges of Existing Debt
Interest rate derivatives
Weighted Average Interest Rate Paid	0.87%
ALABAMA POWER CO | Energy-related, Natural Gas
Energy-related derivative contracts
Net Purchased mmBtu | MMBTU	82
Longest Hedge Date	2022
GEORGIA POWER CO | Energy-related, Natural Gas
Energy-related derivative contracts
Net Purchased mmBtu | MMBTU	174
Longest Hedge Date	2022
GEORGIA POWER CO | Interest rate derivatives | 12/1/2018 | Fair Value Hedges of Existing Debt
Interest rate derivatives
Notional Amount	$ 500,000,000
Interest Rate Received	1.95%
Fair Value Gain (Loss) at June 30, 2018	$ (3,000,000)
GEORGIA POWER CO | Interest rate derivatives | 12/1/2018 | London Interbank Offered Rate (LIBOR) | Fair Value Hedges of Existing Debt
Interest rate derivatives
Weighted Average Interest Rate Paid	0.76%
GEORGIA POWER CO | Interest rate derivatives | 12/1/2019 | Fair Value Hedges of Existing Debt
Interest rate derivatives
Notional Amount	$ 200,000,000
Interest Rate Received	4.25%
Fair Value Gain (Loss) at June 30, 2018	$ (3,000,000)
GEORGIA POWER CO | Interest rate derivatives | 12/1/2019 | London Interbank Offered Rate (LIBOR) | Fair Value Hedges of Existing Debt
Interest rate derivatives
Weighted Average Interest Rate Paid	2.46%
GULF POWER CO | Energy-related, Natural Gas
Energy-related derivative contracts
Net Purchased mmBtu | MMBTU	13
Longest Hedge Date	2020
MISSISSIPPI POWER CO | Energy-related, Natural Gas
Energy-related derivative contracts
Net Purchased mmBtu | MMBTU	66
Longest Hedge Date	2022
SOUTHERN POWER CO | Energy-related, Natural Gas
Energy-related derivative contracts
Net Purchased mmBtu | MMBTU	14
Longest Hedge Date	2020
SOUTHERN Co GAS | Energy-related, Natural Gas
Energy-related derivative contracts
Net Purchased mmBtu | MMBTU	352
Longest Hedge Date	2020
Longest Non-Hedge Date	2029
SOUTHERN Co GAS | Energy-related, Natural Gas | Long | Derivatives not designated as hedging instruments
Energy-related derivative contracts
Derivative nonmonetary notional amount net long short position volume | MMBTU	3,900
SOUTHERN Co GAS | Energy-related, Natural Gas | Short | Derivatives not designated as hedging instruments
Energy-related derivative contracts
Derivative nonmonetary notional amount net long short position volume | MMBTU	3,600

XML

Derivatives - Narrative (Details) MMBTU in Millions	6 Months Ended
	Jun. 30, 2018 USD ($) MMBTU	Dec. 31, 2017 USD ($)
Derivative [Line Items]
Collateral already posted, aggregate fair value | $	$ 183,000,000
Southern Company
Derivative [Line Items]
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints	17
Cash flow hedge gain (loss) to be reclassified within twelve months | $	$ (18,000,000)
ALABAMA POWER CO
Derivative [Line Items]
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints	3
GEORGIA POWER CO
Derivative [Line Items]
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints	6
Gulf Power and Mississippi Power
Derivative [Line Items]
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints	1
MISSISSIPPI POWER CO
Derivative [Line Items]
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints	2
SOUTHERN POWER CO
Derivative [Line Items]
Expected volume of natural gas subject to option to sell back excess gas due to operational constraints	5
Parent Company and Southern Power
Derivative [Line Items]
Foreign currency cash flow hedge gain (loss) to be reclassified during next 12 months | $	$ (23,000,000)
SOUTHERN Co GAS
Derivative [Line Items]
Collateral already posted, aggregate fair value | $	183,000,000	$ 193,000,000
Derivative Counterparties | Registrants
Derivative [Line Items]
Collateral already posted, aggregate fair value | $	$ 0

XML

Derivatives - Foreign Currency Derivatives (Details) - 6 months ended Jun. 30, 2018 - Cash Flow Hedges of Existing Debt - Foreign currency derivatives € in Millions, $ in Millions	USD ($)	EUR (€)
Derivative [Line Items]
Pay Notional	$ 1,241
Receive Notional | €		€ 1,100
Fair Value Gain (Loss) at June 30, 2018	109
SOUTHERN POWER CO | June 2022
Derivative [Line Items]
Pay Notional	$ 677
Pay Rate	2.95%
Receive Notional | €		600
Receive Rate	1.00%
Fair Value Gain (Loss) at June 30, 2018	$ 54
SOUTHERN POWER CO | June 2026
Derivative [Line Items]
Pay Notional	$ 564
Pay Rate	3.78%
Receive Notional | €		€ 500
Receive Rate	1.85%
Fair Value Gain (Loss) at June 30, 2018	$ 55

XML

Derivatives - Derivative Financial Statement Presentation and Amounts With Balance Sheet Offsetting (Details) - USD ($) $ in Millions	Jun. 30, 2018	Dec. 31, 2017
Derivatives, Fair Value [Line Items]
Collateral already posted, aggregate fair value	$ 183
Southern Company
Derivatives, Fair Value [Line Items]
Derivatives, assets	584	$ 700
Derivatives, liabilities	664	794
Derivative asset amount offset	(306)	(405)
Derivative liability amount offset	(489)	(598)
Derivative asset	278	295
Derivative liability	175	196
Southern Company | Derivatives not designated as hedging instruments
Derivatives, Fair Value [Line Items]
Derivatives, assets	428	550
Derivatives, liabilities	518	652
Southern Company | Derivatives not designated as hedging instruments | Energy-related derivatives | Other current assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	239	380
Southern Company | Derivatives not designated as hedging instruments | Energy-related derivatives | Other deferred charges and assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	189	170
Southern Company | Derivatives not designated as hedging instruments | Energy-related derivatives | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	272	437
Southern Company | Derivatives not designated as hedging instruments | Energy-related derivatives | Other deferred credits and liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	246	215
Southern Company | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives
Derivatives, Fair Value [Line Items]
Derivatives, assets	21	17
Derivatives, liabilities	51	67
Southern Company | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other current assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	16	10
Southern Company | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other deferred charges and assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	5	7
Southern Company | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	12	43
Southern Company | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other deferred credits and liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	27	24
Southern Company | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Assets held for sale, noncurrent
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
Southern Company | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Liabilities held for sale, noncurrent
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	4	0
Southern Company | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Assets held for sale, current
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
Southern Company | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Liabilities held for sale, current
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	8	0
Southern Company | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes
Derivatives, Fair Value [Line Items]
Derivatives, assets	135	133
Derivatives, liabilities	95	75
Southern Company | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other current assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	2	3
Southern Company | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other deferred charges and assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	1	0
Southern Company | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	3	14
Southern Company | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other deferred credits and liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	1	0
Southern Company | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Interest rate derivatives | Other current assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	1
Southern Company | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Interest rate derivatives | Other deferred charges and assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
Southern Company | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Interest rate derivatives | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	15	4
Southern Company | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Interest rate derivatives | Other deferred credits and liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	53	34
Southern Company | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Foreign currency derivatives | Other current assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
Southern Company | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Foreign currency derivatives | Other deferred charges and assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	132	129
Southern Company | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Foreign currency derivatives | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	23	23
Southern Company | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Foreign currency derivatives | Other deferred credits and liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	0	0
ALABAMA POWER CO
Derivatives, Fair Value [Line Items]
Derivatives, assets	8	4
Derivatives, liabilities	9	10
Derivative asset amount offset	(4)	(4)
Derivative liability amount offset	(4)	(4)
Derivative asset	4	0
Derivative liability	5	6
ALABAMA POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes
Derivatives, Fair Value [Line Items]
Derivatives, assets	8	4
Derivatives, liabilities	9	10
ALABAMA POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other current assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	6	2
ALABAMA POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other deferred charges and assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	2	2
ALABAMA POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	3	6
ALABAMA POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other deferred credits and liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	6	4
GEORGIA POWER CO
Derivatives, Fair Value [Line Items]
Derivatives, assets	7	6
Derivatives, liabilities	25	24
Derivative asset amount offset	(7)	(6)
Derivative liability amount offset	(7)	(6)
Derivative asset	0	0
Derivative liability	18	18
GEORGIA POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes
Derivatives, Fair Value [Line Items]
Derivatives, assets	7	6
Derivatives, liabilities	19	19
GEORGIA POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other current assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	5	2
GEORGIA POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other deferred charges and assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	2	4
GEORGIA POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	5	9
GEORGIA POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other deferred credits and liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	14	10
GEORGIA POWER CO | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
Derivatives, liabilities	6	5
GEORGIA POWER CO | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Interest rate derivatives | Other current assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
GEORGIA POWER CO | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Interest rate derivatives | Other deferred charges and assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
GEORGIA POWER CO | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Interest rate derivatives | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	5	4
GEORGIA POWER CO | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Interest rate derivatives | Other deferred credits and liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	1	1
GULF POWER CO
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
Derivatives, liabilities	12	21
Derivative asset amount offset	0	0
Derivative liability amount offset	0	0
Derivative asset	0	0
Derivative liability	12	21
GULF POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
Derivatives, liabilities	12	21
GULF POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other current assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
GULF POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other deferred charges and assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
GULF POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	8	14
GULF POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other deferred credits and liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	4	7
MISSISSIPPI POWER CO
Derivatives, Fair Value [Line Items]
Derivatives, assets	3	3
Derivatives, liabilities	9	9
Derivative asset amount offset	(2)	(2)
Derivative liability amount offset	(2)	(2)
Derivative asset	1	1
Derivative liability	7	7
MISSISSIPPI POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes
Derivatives, Fair Value [Line Items]
Derivatives, assets	3	2
Derivatives, liabilities	9	9
MISSISSIPPI POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other current assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	2	1
MISSISSIPPI POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other deferred charges and assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	1	1
MISSISSIPPI POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	3	6
MISSISSIPPI POWER CO | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other deferred credits and liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	6	3
MISSISSIPPI POWER CO | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	1
Derivatives, liabilities	0	0
MISSISSIPPI POWER CO | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Interest rate derivatives | Other current assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	1
MISSISSIPPI POWER CO | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Interest rate derivatives | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	0	0
SOUTHERN POWER CO
Derivatives, Fair Value [Line Items]
Derivatives, assets	135	132
Derivatives, liabilities	26	36
Derivative asset amount offset	(2)	(3)
Derivative liability amount offset	(2)	(3)
Derivative asset	133	129
Derivative liability	24	33
SOUTHERN POWER CO | Derivatives not designated as hedging instruments | Energy-related derivatives | Other current assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
SOUTHERN POWER CO | Derivatives not designated as hedging instruments | Energy-related derivatives | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	0	2
SOUTHERN POWER CO | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes
Derivatives, Fair Value [Line Items]
Derivatives, assets	135	132
Derivatives, liabilities	26	34
SOUTHERN POWER CO | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other current assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	2	3
SOUTHERN POWER CO | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other deferred charges and assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	1	0
SOUTHERN POWER CO | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	2	11
SOUTHERN POWER CO | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other deferred credits and liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	1	0
SOUTHERN POWER CO | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Foreign currency derivatives | Other current assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
SOUTHERN POWER CO | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Foreign currency derivatives | Other deferred charges and assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	132	129
SOUTHERN POWER CO | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Foreign currency derivatives | Other current liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	23	23
SOUTHERN POWER CO | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Foreign currency derivatives | Other deferred credits and liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	0	0
SOUTHERN Co GAS
Derivatives, Fair Value [Line Items]
Derivatives, assets	431	554
Derivatives, liabilities	521	660
Derivative asset amount offset	(291)	(390)
Derivative liability amount offset	(474)	(583)
Derivative asset	140	164
Derivative liability	47	77
Collateral already posted, aggregate fair value	183	193
Weather derivative premium	3	11
SOUTHERN Co GAS | Energy-related derivatives
Derivatives, Fair Value [Line Items]
Collateral already posted, aggregate fair value	2	6
SOUTHERN Co GAS | Derivatives not designated as hedging instruments | Energy-related derivatives
Derivatives, Fair Value [Line Items]
Derivatives, assets	428	549
Derivatives, liabilities	518	649
SOUTHERN Co GAS | Derivatives not designated as hedging instruments | Energy-related derivatives | Other deferred charges and assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	189	170
SOUTHERN Co GAS | Derivatives not designated as hedging instruments | Energy-related derivatives | Other deferred credits and liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	246	215
SOUTHERN Co GAS | Derivatives not designated as hedging instruments | Energy-related derivatives | Assets from risk management activities
Derivatives, Fair Value [Line Items]
Derivatives, assets	239	379
SOUTHERN Co GAS | Derivatives not designated as hedging instruments | Energy-related derivatives | Liabilities from risk management activities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	272	434
SOUTHERN Co GAS | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives
Derivatives, Fair Value [Line Items]
Derivatives, assets	3	5
Derivatives, liabilities	2	8
SOUTHERN Co GAS | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other deferred charges and assets
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
SOUTHERN Co GAS | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Other deferred credits and liabilities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	1	0
SOUTHERN Co GAS | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Assets from risk management activities
Derivatives, Fair Value [Line Items]
Derivatives, assets	3	5
SOUTHERN Co GAS | Derivatives designated as hedging instruments for regulatory purposes | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Liabilities from risk management activities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	1	8
SOUTHERN Co GAS | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Assets from risk management activities
Derivatives, Fair Value [Line Items]
Derivatives, assets	0	0
SOUTHERN Co GAS | Derivatives designated as hedging instruments in cash flow and fair value hedges | Derivatives designated as hedging instruments for regulatory purposes | Energy-related derivatives | Liabilities from risk management activities
Derivatives, Fair Value [Line Items]
Derivatives, liabilities	$ 1	$ 3

XML

Derivatives - Pre-tax Effects of Derivatives Designated as Cash Flow Hedging Instruments (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017
Derivative Instruments, Gain (Loss) [Line Items]
Collateral already posted, aggregate fair value	$ 183		$ 183
Gain (Loss) Recognized in OCI on Derivative	(73)	$ 61	(11)	$ 46
Energy-related derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet	(28)		(28)		$ (44)
Gain (Loss) Recognized in OCI on Derivative	0	(9)	12	(20)
Energy-related derivatives | Other regulatory assets, current
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet	(4)		(4)		(34)
Energy-related derivatives | Other regulatory assets, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet	(20)		(20)		(18)
Energy-related derivatives | Assets held for sale, current
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet	(8)		(8)
Energy-related derivatives | Assets held for sale, noncurrent
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet	(4)		(4)
Energy-related derivatives | Other regulatory liabilities, current
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet	8		8		7
Energy-related derivatives | Other regulatory liabilities, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet					1
Interest rate derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative	0	(1)	(2)	(1)
Foreign currency derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative	(73)	71	(21)	67
ALABAMA POWER CO | Energy-related derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet	(1)		(1)		(6)
ALABAMA POWER CO | Energy-related derivatives | Other regulatory assets, current
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet	(1)		(1)		(4)
ALABAMA POWER CO | Energy-related derivatives | Other regulatory assets, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet	(4)		(4)		(3)
ALABAMA POWER CO | Energy-related derivatives | Assets held for sale, current
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet	0		0
ALABAMA POWER CO | Energy-related derivatives | Assets held for sale, noncurrent
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet	0		0
ALABAMA POWER CO | Energy-related derivatives | Other regulatory liabilities, current
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet	4		4		0
ALABAMA POWER CO | Energy-related derivatives | Other regulatory liabilities, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet					1
GEORGIA POWER CO | Energy-related derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet	(12)		(12)		(13)
GEORGIA POWER CO | Energy-related derivatives | Other regulatory assets, current
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet	(1)		(1)		(7)
GEORGIA POWER CO | Energy-related derivatives | Other regulatory assets, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet	(11)		(11)		(6)
GEORGIA POWER CO | Energy-related derivatives | Assets held for sale, current
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet	0		0
GEORGIA POWER CO | Energy-related derivatives | Assets held for sale, noncurrent
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet	0		0
GEORGIA POWER CO | Energy-related derivatives | Other regulatory liabilities, current
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet	0		0		0
GEORGIA POWER CO | Energy-related derivatives | Other regulatory liabilities, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet					0
GULF POWER CO | Energy-related derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet	(12)		(12)		(21)
GULF POWER CO | Energy-related derivatives | Other regulatory assets, current
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet	(8)		(8)		(14)
GULF POWER CO | Energy-related derivatives | Other regulatory assets, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet	(4)		(4)		(7)
GULF POWER CO | Energy-related derivatives | Assets held for sale, current
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet	0		0
GULF POWER CO | Energy-related derivatives | Assets held for sale, noncurrent
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet	0		0
GULF POWER CO | Energy-related derivatives | Other regulatory liabilities, current
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet	0		0		0
GULF POWER CO | Energy-related derivatives | Other regulatory liabilities, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet					0
MISSISSIPPI POWER CO | Energy-related derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet	(6)		(6)		(7)
MISSISSIPPI POWER CO | Energy-related derivatives | Other regulatory assets, current
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet	(1)		(1)		(5)
MISSISSIPPI POWER CO | Energy-related derivatives | Other regulatory assets, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet	(5)		(5)		(2)
MISSISSIPPI POWER CO | Energy-related derivatives | Assets held for sale, current
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet	0		0
MISSISSIPPI POWER CO | Energy-related derivatives | Assets held for sale, noncurrent
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet	0		0
MISSISSIPPI POWER CO | Energy-related derivatives | Other regulatory liabilities, current
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet	0		0		0
MISSISSIPPI POWER CO | Energy-related derivatives | Other regulatory liabilities, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet					0
SOUTHERN Co GAS
Derivative Instruments, Gain (Loss) [Line Items]
Collateral already posted, aggregate fair value	183		183		193
SOUTHERN Co GAS | Energy-related derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet	3		3		3
Collateral already posted, aggregate fair value	2		2		6
Gain (Loss) Recognized in OCI on Derivative	1	(2)	2	(4)
SOUTHERN Co GAS | Energy-related derivatives | Other regulatory assets, current
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet	(1)		(1)		(4)
SOUTHERN Co GAS | Energy-related derivatives | Other regulatory assets, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet	0		0		0
SOUTHERN Co GAS | Energy-related derivatives | Assets held for sale, current
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet	0		0
SOUTHERN Co GAS | Energy-related derivatives | Assets held for sale, noncurrent
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet	0		0
SOUTHERN Co GAS | Energy-related derivatives | Other regulatory liabilities, current
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet	4		4		7
SOUTHERN Co GAS | Energy-related derivatives | Other regulatory liabilities, deferred
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory hedge unrealized gain (loss) recognized on the balance sheet					$ 0
SOUTHERN POWER CO
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative	(74)	64	(11)	52
SOUTHERN POWER CO | Energy-related derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative	(1)	(7)	10	(15)
SOUTHERN POWER CO | Foreign currency derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in OCI on Derivative	$ (73)	$ 71	$ (21)	$ 67

XML

Derivatives - Location and Amount of Gain (Loss) Recognized in Income on Cash Flow and Fair Value Hedging Relationships (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Derivative [Line Items]
Depreciation and amortization	$ 783	$ 754	$ 1,552	$ 1,469
Interest expense, net of amounts capitalized	(470)	(424)	(928)	(840)
Other income (expense), net	78	52	138	98
Cost of natural gas	228	232	949	951
Other income (expense), net | Foreign currency derivatives
Derivative [Line Items]
Gain (loss) recognized in income	(73)	79	(37)	96
Cash Flow Hedging | Depreciation and amortization | Energy-related derivatives
Derivative [Line Items]
Gain (loss) recognized in income	1	(2)	2	(6)
Cash Flow Hedging | Interest expense, net of amounts capitalized | Interest rate derivatives
Derivative [Line Items]
Gain (loss) recognized in income	(6)	(5)	(11)	(10)
Cash Flow Hedging | Interest expense, net of amounts capitalized | Foreign currency derivatives
Derivative [Line Items]
Gain (loss) recognized in income	(7)	(5)	(12)	(12)
Cash Flow Hedging | Cost of natural gas | Energy-related derivatives
Derivative [Line Items]
Gain (loss) recognized in income	0	0	(2)	0
Fair Value Hedging | Interest expense, net of amounts capitalized | Interest rate derivatives
Derivative [Line Items]
Gain (loss) recognized in income	(7)	7	(31)	(1)
ALABAMA POWER CO
Derivative [Line Items]
Depreciation and amortization	189	183	379	364
Interest expense, net of amounts capitalized	(80)	(77)	(158)	(153)
Other income (expense), net	12	15	15	25
ALABAMA POWER CO | Interest expense, net of amounts capitalized | Interest rate derivatives
Derivative [Line Items]
Gain (loss) recognized in income	(1)	(2)	(3)	(3)
GEORGIA POWER CO
Derivative [Line Items]
Depreciation and amortization	230	223	458	444
Interest expense, net of amounts capitalized	(102)	(104)	(208)	(205)
Other income (expense), net	35	34	73	71
GEORGIA POWER CO | Interest expense, net of amounts capitalized | Interest rate derivatives
Derivative [Line Items]
Gain (loss) recognized in income	(2)	(1)	(3)	(3)
GEORGIA POWER CO | Fair Value Hedging | Interest expense, net of amounts capitalized | Interest rate derivatives
Derivative [Line Items]
Gain (loss) recognized in income	2	0	(1)	(1)
MISSISSIPPI POWER CO
Derivative [Line Items]
Depreciation and amortization	44	41	84	81
Interest expense, net of amounts capitalized	(21)	(17)	(39)	(37)
Other income (expense), net	27	3	27	5
MISSISSIPPI POWER CO | Interest expense, net of amounts capitalized | Interest rate derivatives
Derivative [Line Items]
Gain (loss) recognized in income	(1)	0	(1)	(1)
SOUTHERN POWER CO
Derivative [Line Items]
Depreciation and amortization	125	129	240	247
Interest expense, net of amounts capitalized	(46)	(48)	(93)	(97)
Other income (expense), net	2	2	5	(2)
SOUTHERN POWER CO | Cash Flow Hedging | Depreciation and amortization | Energy-related derivatives
Derivative [Line Items]
Gain (loss) recognized in income	1	(2)	2	(6)
SOUTHERN POWER CO | Cash Flow Hedging | Interest expense, net of amounts capitalized | Foreign currency derivatives
Derivative [Line Items]
Gain (loss) recognized in income	(7)	(5)	(12)	(12)
SOUTHERN POWER CO | Cash Flow Hedging | Other income (expense), net | Foreign currency derivatives
Derivative [Line Items]
Gain (loss) recognized in income	(73)	79	(37)	96
SOUTHERN Co GAS
Derivative [Line Items]
Depreciation and amortization	126	125	255	244
Interest expense, net of amounts capitalized	(59)	(48)	(118)	(94)
Other income (expense), net	3	4	15	10
Cost of natural gas	228	232	949	951
SOUTHERN Co GAS | Cost of natural gas | Energy-related derivatives
Derivative [Line Items]
Gain (loss) recognized in income	$ 0	$ 0	$ (2)	$ 0

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Derivatives - Cumulative Basis Adjustments for Fair Value Hedges (Details) - Fair Value Hedging - USD ($) $ in Millions	Jun. 30, 2018	Dec. 31, 2017
Securities due within one year
Derivative [Line Items]
Carrying Amount of the Hedged Item	$ (497)	$ (746)
Cumulative Amount of Fair Value Hedging Adjustment included in Carrying Amount of the Hedged Item	3	3
Securities due within one year | GEORGIA POWER CO
Derivative [Line Items]
Carrying Amount of the Hedged Item	(497)	(746)
Cumulative Amount of Fair Value Hedging Adjustment included in Carrying Amount of the Hedged Item	3	3
Long-term Debt
Derivative [Line Items]
Carrying Amount of the Hedged Item	(2,528)	(2,553)
Cumulative Amount of Fair Value Hedging Adjustment included in Carrying Amount of the Hedged Item	63	35
Long-term Debt | GEORGIA POWER CO
Derivative [Line Items]
Carrying Amount of the Hedged Item	(497)	(498)
Cumulative Amount of Fair Value Hedging Adjustment included in Carrying Amount of the Hedged Item	$ 3	$ 1

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Derivatives - Pre-tax Effects of Derivatives Not Designated as Hedging (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Energy-related derivatives | Derivatives not designated as hedging instruments
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss), net	$ (26)	$ 14	$ (39)	$ 61
Energy-related derivatives | Natural gas revenues | Derivatives not designated as hedging instruments
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss), net	(28)	16	(43)	65
Energy-related derivatives | Cost of natural gas | Derivatives not designated as hedging instruments
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss), net	2	(2)	4	(4)
Southern Company | Weather Derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, gain (loss) on derivative, net	0	0	0	15
SOUTHERN Co GAS
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, gain (loss) on derivative, net			(2)	49
SOUTHERN Co GAS | Energy-related derivatives | Derivatives not designated as hedging instruments
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss), net	(26)	14	(39)	61
SOUTHERN Co GAS | Energy-related derivatives | Natural gas revenues | Derivatives not designated as hedging instruments
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss), net	(28)	16	(43)	65
SOUTHERN Co GAS | Energy-related derivatives | Cost of natural gas | Derivatives not designated as hedging instruments
Derivative Instruments, Gain (Loss) [Line Items]
Derivative instruments not designated as hedging instruments, gain (loss), net	$ 2	$ (2)	$ 4	$ (4)

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Acquisitions and Dispositions - Southern Company (Details) - Scenario, Forecast - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2019	Jun. 28, 2019
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Stock purchase agreement, contract termination fees		$ 100
Disposal Group, Disposed of by Sale, Not Discontinued Operations | GULF POWER CO
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from divestiture of businesses, net of cash divested	$ 5,750
Amount of indebtedness assumed at closing	$ 1,400
700 Universe, LLC | Minimum
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Stock purchase agreement, contract termination fees		100
700 Universe, LLC | Maximum
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Stock purchase agreement, contract termination fees		$ 200

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Acquisitions and Dispositions - Schedule of Construction Projects (Details) - SOUTHERN POWER CO - MW	1 Months Ended		3 Months Ended
	Jul. 31, 2018	Mar. 31, 2018	Dec. 31, 2019	Jun. 30, 2019	Aug. 07, 2018	Jun. 30, 2018	May 31, 2018	Jul. 31, 2017
Gaskell West 1
Business Acquisition [Line Items]
Approximate Nameplate Capacity (MW)						20
PPA Contract Period		20 years
Cactus Flats
Business Acquisition [Line Items]
Southern Power Percentage Ownership								100.00%
Wildhorse
Business Acquisition [Line Items]
Southern Power Percentage Ownership							100.00%
Scenario, Forecast | Cactus Flats
Business Acquisition [Line Items]
Approximate Nameplate Capacity (MW)	148
Scenario, Forecast | Mankato
Business Acquisition [Line Items]
Approximate Nameplate Capacity (MW)				345
PPA Contract Period				20 years
Scenario, Forecast | Wildhorse
Business Acquisition [Line Items]
Approximate Nameplate Capacity (MW)			100
PPA Contract Period			20 years
Minimum | Scenario, Forecast | Cactus Flats
Business Acquisition [Line Items]
PPA Contract Period	12 years
Maximum | Scenario, Forecast | Cactus Flats
Business Acquisition [Line Items]
PPA Contract Period	15 years
Common Class B | Gaskell West 1
Business Acquisition [Line Items]
Southern Power Percentage Ownership						100.00%
Class B Membership Interest | Gaskell West 1
Business Acquisition [Line Items]
Southern Power Percentage Ownership						100.00%
Class B Membership Interest | Cactus Flats
Business Acquisition [Line Items]
Southern Power Percentage Ownership							100.00%
Subsequent Event | Class B Membership Interest | Cactus Flats
Business Acquisition [Line Items]
Southern Power Percentage Ownership					100.00%

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Acquisitions and Dispositions - Southern Power Narrative (Details) - USD ($) $ in Thousands			1 Months Ended	3 Months Ended	6 Months Ended		12 Months Ended	36 Months Ended
	May 25, 2018	May 20, 2018	May 31, 2018	Jun. 30, 2018	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2017
Business Acquisition [Line Items]
Construction work in progress				$ 6,947,000	$ 6,947,000				$ 6,904,000
Sale of SPSH noncontrolling interests					1,283,000
Assets subject to lien				112,777,000	112,777,000				111,005,000
SOUTHERN POWER CO
Business Acquisition [Line Items]
Construction work in progress				771,000	771,000				511,000
Sale of SPSH noncontrolling interests			$ 511,000
Repayments of debt			770,000
Repayments of capital			250,000		250,000	$ 0
Assets subject to lien				15,428,000	15,428,000				$ 15,206,000
SOUTHERN POWER CO | Series of Construction Projects
Business Acquisition [Line Items]
Construction work in progress				353,000	353,000
SOUTHERN POWER CO | Minimum | Series of Construction Projects
Business Acquisition [Line Items]
Estimated future construction payments				520,000	520,000
SOUTHERN POWER CO | Maximum | Series of Construction Projects
Business Acquisition [Line Items]
Estimated future construction payments				590,000	590,000
Wind Generating Facility | Scenario, Forecast | SOUTHERN POWER CO
Business Acquisition [Line Items]
Project qualification for production tax credits, percentage							80.00%	100.00%
Disposal Group, Held-for-sale, Not Discontinued Operations | Florida Plants | SOUTHERN POWER CO
Business Acquisition [Line Items]
Proceeds from sale of equity method investments			195,000
Decrease in consideration per day between end of fiscal year and closing			110
Increase in consideration per day if closing is prior to end of fiscal year			$ 110
Pre-tax impairment charge				119,000	119,000
After tax impairment charge				$ 89,000	88,000
SP Solar Holdings I, LP | SOUTHERN POWER CO
Business Acquisition [Line Items]
Limited liability company or limited partnership, members or limited partners, ownership interest		33.00%	33.00%	33.00%
Proceeds from sale of equity method investments	$ 1,200,000
Common Stockholders' Equity
Business Acquisition [Line Items]
Sale of SPSH noncontrolling interests					(407,000)
Senior Lien [Member] | SOUTHERN POWER CO | Mankato
Business Acquisition [Line Items]
Assets subject to lien				$ 475,000	$ 475,000

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Acquisitions and Dispositions - Southern Company Gas (Details) $ in Millions				3 Months Ended			6 Months Ended
	Jul. 29, 2018 USD ($)	Jul. 01, 2018 USD ($) utility	Jun. 04, 2018 USD ($)	Jun. 30, 2018 USD ($)	Mar. 31, 2018 USD ($)	Jun. 30, 2017 USD ($)	Jun. 30, 2018 USD ($)	Jun. 30, 2017 USD ($)	Aug. 07, 2018 utility
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Goodwill impairment							$ 42
SOUTHERN Co GAS
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Goodwill impairment				$ 0	$ 42	$ 0	42	$ 0
Gain (loss) on disposition of business				(36)		$ 0	(36)	$ 0
Pivotal Home Solutions | Disposal Group, Disposed of by Sale, Not Discontinued Operations | SOUTHERN Co GAS
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash purchase price on sale of business			$ 358
Working capital adjustment			6
Gain (loss) on disposition of business, after tax			(76)
Tax on gain (loss) on disposition of business			$ 40
Goodwill impairment					$ 42		42
Florida City Gas | Disposal Group, Disposed of by Sale, Not Discontinued Operations | SOUTHERN Co GAS
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Long-term debt				$ 3			$ 3
Subsequent Event | Disposal Group, Disposed of by Sale, Not Discontinued Operations | SOUTHERN Co GAS
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Number of natural gas distribution utilities disposed | utility									3
Subsequent Event | Elizabethtown Gas and Elkton Gas | Disposal Group, Disposed of by Sale, Not Discontinued Operations | SOUTHERN Co GAS
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash purchase price on sale of business		$ 1,700
Working capital adjustment		40
Gain (loss) on disposition of business, after tax		$ (12)
Number of natural gas distribution utilities disposed | utility		2
Gain (loss) on disposition of business		$ 235
Subsequent Event | Florida City Gas | Disposal Group, Disposed of by Sale, Not Discontinued Operations | SOUTHERN Co GAS
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash purchase price on sale of business	$ 530
Gain (loss) on disposition of business, after tax	4
Gain (loss) on disposition of business	126
Additional cash amount	$ 60

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Acquisitions and Dispositions - Held for Sale (Details) - USD ($) $ in Millions	Jun. 30, 2018	Dec. 31, 2017
Assets Held for Sale:
Current assets	$ 2,704	$ 12
Liabilities Held for Sale:
Current liabilities	706	0
Other non-current liabilities	2,833	0
SOUTHERN POWER CO
Assets Held for Sale:
Current assets	17	1
Liabilities Held for Sale:
Current liabilities	2	0
SOUTHERN Co GAS
Assets Held for Sale:
Current assets	2,298	0
Liabilities Held for Sale:
Current liabilities	412	$ 0
Disposal Group, Held-for-sale, Not Discontinued Operations
Assets Held for Sale:
Current assets	487
Total property, plant, and equipment	5,462
Goodwill and other intangible assets	668
Other non-current assets	705
Total Assets Held for Sale	7,322
Liabilities Held for Sale:
Current liabilities	354
Long-term debt	1,285
Accumulated deferred income taxes	566
Other non-current liabilities	1,334
Total Liabilities Held for Sale	3,539
Disposal Group, Held-for-sale, Not Discontinued Operations | SOUTHERN POWER CO
Assets Held for Sale:
Current assets	17
Total property, plant, and equipment	168
Goodwill and other intangible assets	0
Other non-current assets	15
Total Assets Held for Sale	200
Liabilities Held for Sale:
Current liabilities	2
Long-term debt	0
Accumulated deferred income taxes	0
Other non-current liabilities	0
Total Liabilities Held for Sale	2
Disposal Group, Held-for-sale, Not Discontinued Operations | SOUTHERN Co GAS
Assets Held for Sale:
Current assets	81
Total property, plant, and equipment	1,408
Goodwill and other intangible assets	668
Other non-current assets	141
Total Assets Held for Sale	2,298
Liabilities Held for Sale:
Current liabilities	61
Long-term debt	0
Accumulated deferred income taxes	26
Other non-current liabilities	325
Total Liabilities Held for Sale	$ 412

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Acquisitions and Dispositions - Pre-tax Profit (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
GULF POWER CO
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Earnings before income taxes:	$ 31	$ 61	$ 87	$ 95
Florida Plants | SOUTHERN POWER CO
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Earnings before income taxes:	$ 14	$ 11	$ 24	$ 20

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Variable Interest Entity and Equity Method Investments - Narrative (Details) - USD ($) $ in Billions		1 Months Ended	3 Months Ended	6 Months Ended
	May 20, 2018	May 31, 2018	Jun. 30, 2018	Jun. 30, 2018
SOUTHERN POWER CO
Schedule of Equity Method Investments [Line Items]
Distribution made to limited partner, cash distributions paid, percentage				67.00%
Global Atlantic
Schedule of Equity Method Investments [Line Items]
Distribution made to limited partner, cash distributions paid, percentage				33.00%
SP Solar Holdings I, LP | SOUTHERN POWER CO
Schedule of Equity Method Investments [Line Items]
Limited liability company or limited partnership, members or limited partners, ownership interest	33.00%	33.00%	33.00%
Wholly Owned Subsidiary Of Southern Power | SP Solar Holdings I, LP | SOUTHERN POWER CO
Schedule of Equity Method Investments [Line Items]
Limited liability company (llc) or limited partnership (lp), managing member or general partner, ownership interest	66.00%
Variable Interest Entity, Primary Beneficiary | SP Solar Holdings I, LP | SOUTHERN POWER CO
Schedule of Equity Method Investments [Line Items]
Assets			$ 6.5	$ 6.5
Liabilities			0.1	0.1
Noncontrolling Interest in Variable Interest Entity			$ 1.2	$ 1.2
General Partner | Wholly Owned Subsidiary Of Southern Power | SP Solar Holdings I, LP | SOUTHERN POWER CO
Schedule of Equity Method Investments [Line Items]
Limited liability company (llc) or limited partnership (lp), managing member or general partner, ownership interest	1.00%

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Variable Interest Entity and Equity Method Investments - Balance Sheet Equity Method Investment Carrying Amount (Details) - USD ($) $ in Millions	Jun. 30, 2018	Dec. 31, 2017
Schedule of Equity Method Investments [Line Items]
Equity investments in unconsolidated subsidiaries	$ 1,546	$ 1,513
SOUTHERN Co GAS
Schedule of Equity Method Investments [Line Items]
Equity investments in unconsolidated subsidiaries	1,507	1,477
SNG | SOUTHERN Co GAS
Schedule of Equity Method Investments [Line Items]
Equity investments in unconsolidated subsidiaries	1,258	1,262
Atlantic Coast Pipeline | SOUTHERN Co GAS
Schedule of Equity Method Investments [Line Items]
Equity investments in unconsolidated subsidiaries	56	41
PennEast Pipeline | SOUTHERN Co GAS
Schedule of Equity Method Investments [Line Items]
Equity investments in unconsolidated subsidiaries	67	57
Triton | SOUTHERN Co GAS
Schedule of Equity Method Investments [Line Items]
Equity investments in unconsolidated subsidiaries	42	42
Pivotal JAX LNG, LLC | SOUTHERN Co GAS
Schedule of Equity Method Investments [Line Items]
Equity investments in unconsolidated subsidiaries	52	44
Horizon Pipeline | SOUTHERN Co GAS
Schedule of Equity Method Investments [Line Items]
Equity investments in unconsolidated subsidiaries	31	30
Other | SOUTHERN Co GAS
Schedule of Equity Method Investments [Line Items]
Equity investments in unconsolidated subsidiaries	$ 1	$ 1

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Variable Interest Entity and Equity Method Investments - Income Statement Equity Method Investment Carrying Amount (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Schedule of Equity Method Investments [Line Items]
Earnings from equity method investments	$ 31	$ 28	$ 72	$ 67
SOUTHERN Co GAS
Schedule of Equity Method Investments [Line Items]
Earnings from equity method investments	31	29	74	68
SOUTHERN Co GAS | SNG
Schedule of Equity Method Investments [Line Items]
Earnings from equity method investments	27	24	66	58
SOUTHERN Co GAS | PennEast Pipeline
Schedule of Equity Method Investments [Line Items]
Earnings from equity method investments	1	1	2	4
SOUTHERN Co GAS | Atlantic Coast Pipeline
Schedule of Equity Method Investments [Line Items]
Earnings from equity method investments	1	2	3	3
SOUTHERN Co GAS | Triton
Schedule of Equity Method Investments [Line Items]
Earnings from equity method investments	1	2	2	2
SOUTHERN Co GAS | Horizon Pipeline
Schedule of Equity Method Investments [Line Items]
Earnings from equity method investments	$ 1	$ 0	$ 1	$ 1

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Variable Interest Entity and Equity Method Investments - Investment in SNG (Details) - SNG - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Schedule of Equity Method Investments [Line Items]
Revenues	$ 146	$ 143	$ 306	$ 298
Operating income	60	63	159	147
Net income	$ 54	$ 48	$ 132	$ 114

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Segment and Related Information - Narrative (Details) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018 USD ($) utility state	Jun. 30, 2017 USD ($)	Jun. 30, 2018 USD ($) utility state segment	Jun. 30, 2017 USD ($)	Aug. 07, 2018 utility state
Segment Reporting Information [Line Items]
Number of reportable segments | segment			4
Number of states in which entity operates | state	4		4
Natural gas revenues	$ 706	$ 684	$ 2,314	$ 2,214
SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Number of reportable segments | segment			4
Number of states in which entity operates | state	7		7
Number of natural gas distribution utilities | utility	7		7
Natural gas revenues	$ 710	684	$ 2,341	2,205
SOUTHERN POWER CO
Segment Reporting Information [Line Items]
Wholesale revenues, affiliates	109	90	192	190
Traditional Electric Operating Companies | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Natural gas revenues	8	10	8	10
Southern Company | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Natural gas revenues	$ 22	$ 33	$ 58	$ 56
Subsequent Event | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Number of states in which entity operates | state					4
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Subsequent Event | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Number of natural gas distribution utilities disposed | utility					3

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Segment and Related Information - Financial Data for Business Segments (Details) $ in Millions	3 Months Ended			6 Months Ended
	Jun. 30, 2018 USD ($) utility	Mar. 31, 2018 USD ($)	Jun. 30, 2017 USD ($)	Jun. 30, 2018 USD ($) utility	Jun. 30, 2017 USD ($)	Dec. 31, 2017 USD ($)
Segment Reporting Information [Line Items]
Operating revenues	$ 5,627		$ 5,430	$ 11,999	$ 11,202
Segment net income	(154)		(1,381)	784	(723)
Goodwill	5,315			5,315		$ 6,268
Total assets	112,777			112,777		111,005
Goodwill impairment				42
Plant Scherer Unit 3
Segment Reporting Information [Line Items]
After tax charge to income					20
Loss on Plant Scherer Unit 3					33
Eliminations
Segment Reporting Information [Line Items]
Operating revenues	(49)		(37)	(100)	(79)
Segment net income	3		(2)	4	0
Goodwill	0			0		0
Total assets	(1,791)			(1,791)		(1,619)
Electric Utilities
Segment Reporting Information [Line Items]
Operating revenues	4,565		4,585	8,948	8,716
Segment net income	(26)		(1,360)	706	(859)
Goodwill	2			2		2
Total assets	88,749			88,749		87,085
SOUTHERN Co GAS | Operating Segments
Segment Reporting Information [Line Items]
Operating revenues	730		716	2,369	2,276
Segment net income	(31)		49	248	288
Goodwill	5,015			5,015		5,967
Total assets	22,112			22,112		22,987
All Other | Operating Segments
Segment Reporting Information [Line Items]
Operating revenues	381		166	782	289
Segment net income	(100)		(68)	(174)	(152)
Goodwill	298			298		299
Total assets	3,707			3,707		2,552
GEORGIA POWER AND MISSISSIPPI POWER CO | Kemper County Energy Facility
Segment Reporting Information [Line Items]
Public utilities, property, plant and equipment, amount of loss (recovery) on plant abandonment	1,060		3,000	1,100	3,100
Public utilities, property, plant and equipment, amount of loss (recovery) on plant abandonment after tax	800		2,100	800	2,200
SOUTHERN POWER CO
Segment Reporting Information [Line Items]
Operating revenues	555		529	1,064	979
Segment net income	22		82	143	151
Total assets	15,428			15,428		15,206
SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Operating revenues	730		716	2,369	2,276
Segment net income	(31)		49	248	288
Goodwill	5,015			5,015		5,967
Total assets	22,112			22,112		22,987
Goodwill impairment	0	$ 42	0	42	0
Loss on disposition	36		0	36	0
SOUTHERN Co GAS | Operating Segments
Segment Reporting Information [Line Items]
Operating revenues	734		769	2,405	2,393
Segment net income	(15)		50	274	282
Total assets	23,351			23,351		24,842
SOUTHERN Co GAS | Eliminations
Segment Reporting Information [Line Items]
Operating revenues	(5)		(56)	(38)	(122)
Segment net income	0		0	0	0
Total assets	(12,783)			(12,783)		(14,039)
SOUTHERN Co GAS | All Other | Operating Segments
Segment Reporting Information [Line Items]
Operating revenues	1		3	2	5
Segment net income	(16)		(1)	(26)	6
Total assets	11,544			11,544		12,184
SOUTHERN Co GAS | Gas Distribution Operations
Segment Reporting Information [Line Items]
Goodwill	4,034			4,034		4,702
Goodwill impairment				0
SOUTHERN Co GAS | Gas Distribution Operations | Operating Segments
Segment Reporting Information [Line Items]
Operating revenues	643		603	1,856	1,783
Segment net income	68		54	216	171
Total assets	18,654			18,654		19,358
Revenue on disposition	70		66
Net income on disposition				237	224
SOUTHERN Co GAS | Gas Marketing Services
Segment Reporting Information [Line Items]
Goodwill	981			981		1,265
Goodwill impairment				42
SOUTHERN Co GAS | Gas Marketing Services | Operating Segments
Segment Reporting Information [Line Items]
Operating revenues	89		166	359	454
Segment net income	(76)		4	(63)	35
Total assets	1,610			1,610		2,147
Revenue on disposition	24		32
Net income on disposition				55	63
Loss on disposition	36			36
SOUTHERN Co GAS | Wholesale Gas Services | Operating Segments
Segment Reporting Information [Line Items]
Operating revenues	(16)		(12)	150	119
Segment net income	(21)		(17)	83	51
Total assets	818			818		1,096
Less Gross Gas Costs	1,454		1,666	3,393	3,510
SOUTHERN Co GAS | Gas Midstream Operations | Operating Segments
Segment Reporting Information [Line Items]
Operating revenues	18		12	40	37
Segment net income	14		9	38	25
Total assets	2,269			2,269		2,241
Third Party Gross Revenues | SOUTHERN Co GAS | Wholesale Gas Services | Operating Segments
Segment Reporting Information [Line Items]
Operating revenues	1,336		1,531	3,274	3,370
Intercompany Revenues | SOUTHERN Co GAS | Wholesale Gas Services | Operating Segments
Segment Reporting Information [Line Items]
Operating revenues	102		123	269	259
Total Gross Revenues | SOUTHERN Co GAS | Wholesale Gas Services | Operating Segments
Segment Reporting Information [Line Items]
Operating revenues	1,438		1,654	3,543	3,629
Reportable Subsegments | Traditional Electric Operating Companies | Electric Utilities
Segment Reporting Information [Line Items]
Operating revenues	4,124		4,157	8,104	7,943
Segment net income	(48)		(1,442)	563	(1,010)
Goodwill	0			0		0
Total assets	73,634			73,634		72,204
Reportable Subsegments | SOUTHERN POWER CO | Electric Utilities
Segment Reporting Information [Line Items]
Operating revenues	555		529	1,064	979
Segment net income	22		82	143	151
Goodwill	2			2		2
Total assets	15,428			15,428		15,206
Intersubsegment Eliminations | Electric Utilities
Segment Reporting Information [Line Items]
Operating revenues	(114)		(101)	(220)	(206)
Segment net income	0		$ 0	0	$ 0
Goodwill	0			0		0
Total assets	(313)			(313)		$ (325)
Disposal Group, Held-for-sale, Not Discontinued Operations | Florida Plants | SOUTHERN POWER CO
Segment Reporting Information [Line Items]
Pre-tax impairment charge	119			119
After tax impairment charge	$ 89			$ 88
Disposal Group, Disposed of by Sale, Not Discontinued Operations | SOUTHERN Co GAS | Gas Distribution Operations | Operating Segments
Segment Reporting Information [Line Items]
Number of natural gas distribution utilities disposed | utility	3			3
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Pivotal Home Solutions | SOUTHERN Co GAS
Segment Reporting Information [Line Items]
Goodwill impairment		$ 42		$ 42

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Segment and Related Information - Financial Data for Products and Services (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Revenue from External Customer [Line Items]
Electric Utilities' Revenues	$ 4,565	$ 4,585	$ 8,948	$ 8,716
Southern Company Gas' Revenues	730	716	2,369	2,276
Retail
Revenue from External Customer [Line Items]
Electric Utilities' Revenues	3,740	3,777	7,308	7,171
Wholesale
Revenue from External Customer [Line Items]
Electric Utilities' Revenues	611	618	1,230	1,149
Other
Revenue from External Customer [Line Items]
Electric Utilities' Revenues	214	190	410	396
Gas Distribution Operations
Revenue from External Customer [Line Items]
Southern Company Gas' Revenues	638	557	1,838	1,689
Gas Marketing Services
Revenue from External Customer [Line Items]
Southern Company Gas' Revenues	89	166	359	454
Other
Revenue from External Customer [Line Items]
Southern Company Gas' Revenues	$ 3	$ (7)	$ 172	$ 133