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Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

☑ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2019

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		58-0690070

(A Delaware Corporation)

30 Ivan Allen Jr. Boulevard, N.W.

Atlanta, Georgia 30308

(404) 506-5000

	1-3164		Alabama Power Company		63-0004250

(An Alabama Corporation)

600 North 18th Street

Birmingham, Alabama 35203

(205) 257-1000

	1-6468		Georgia Power Company		58-0257110

(A Georgia Corporation)

241 Ralph McGill Boulevard, N.E.

Atlanta, Georgia 30308

(404) 506-6526

	001-11229		Mississippi Power Company		64-0205820

(A Mississippi Corporation)

2992 West Beach Boulevard

Gulfport, Mississippi 39501

(228) 864-1211

	001-37803		Southern Power Company		58-2598670

(A Delaware Corporation)

30 Ivan Allen Jr. Boulevard, N.W.

Atlanta, Georgia 30308

(404) 506-5000

	1-14174		Southern Company Gas		58-2210952

(A Georgia Corporation)

Ten Peachtree Place, N.E.

Atlanta, Georgia 30309

(404) 584-4000

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Securities registered pursuant to Section 12(b) of the Act:

Registrant	Title of Each Class	Trading Symbol(s)	Name of Each Exchange on Which Registered
The Southern Company	Common Stock, par value $5 per share	SO	New York Stock Exchange
			(NYSE)
The Southern Company	Series 2015A 6.25% Junior Subordinated Notes due 2075	SOJA	NYSE
The Southern Company	Series 2016A 5.25% Junior Subordinated Notes due 2076	SOJB	NYSE
The Southern Company	Series 2017B 5.25% Junior Subordinated Notes due 2077	SOJC	NYSE
Alabama Power Company	5.00% Series Class A Preferred Stock	ALP PR Q	NYSE
Georgia Power Company	Series 2017A 5.00% Junior Subordinated Notes due 2077	GPJA	NYSE
Southern Power Company	Series 2016A 1.000% Senior Notes due 2022	SO/22B	NYSE
Southern Power Company	Series 2016B 1.850% Senior Notes due 2026	SO/26A	NYSE

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 every Interactive Data File required to be submitted 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 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.

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
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, 2019
The Southern Company	Par Value $5 Per Share	1,045,231,646
Alabama Power Company	Par Value $40 Per Share	30,537,500
Georgia Power Company	Without Par Value	9,261,500
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, 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

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INDEX TO QUARTERLY REPORT ON FORM 10-Q

June 30, 2019

		Page Number
DEFINITIONS		5
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION		9
	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	12
	Condensed Consolidated Statements of Comprehensive Income	13
	Condensed Consolidated Statements of Cash Flows	14
	Condensed Consolidated Balance Sheets	15
	Condensed Consolidated Statements of Stockholders' Equity	17
	Management's Discussion and Analysis of Financial Condition and Results of Operations	19
	Alabama Power Company
	Condensed Statements of Income	51
	Condensed Statements of Comprehensive Income	51
	Condensed Statements of Cash Flows	52
	Condensed Balance Sheets	53
	Condensed Statements of Common Stockholder's Equity	55
	Management's Discussion and Analysis of Financial Condition and Results of Operations	56
	Georgia Power Company
	Condensed Statements of Income	68
	Condensed Statements of Comprehensive Income	68
	Condensed Statements of Cash Flows	69
	Condensed Balance Sheets	70
	Condensed Statements of Common Stockholder's Equity	72
	Management's Discussion and Analysis of Financial Condition and Results of Operations	73
	Mississippi Power Company
	Condensed Statements of Income	94
	Condensed Statements of Comprehensive Income	94
	Condensed Statements of Cash Flows	95
	Condensed Balance Sheets	96
	Condensed Statements of Common Stockholder's Equity	98
	Management's Discussion and Analysis of Financial Condition and Results of Operations	99
	Southern Power Company and Subsidiary Companies
	Condensed Consolidated Statements of Income	113
	Condensed Consolidated Statements of Comprehensive Income	113
	Condensed Consolidated Statements of Cash Flows	114
	Condensed Consolidated Balance Sheets	115
	Condensed Consolidated Statements of Stockholders' Equity	117
	Management's Discussion and Analysis of Financial Condition and Results of Operations	119

3

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INDEX TO QUARTERLY REPORT ON FORM 10-Q

June 30, 2019

		Page Number
	PART I—FINANCIAL INFORMATION (CONTINUED)
	Southern Company Gas and Subsidiary Companies
	Condensed Consolidated Statements of Income	132
	Condensed Consolidated Statements of Comprehensive Income	132
	Condensed Consolidated Statements of Cash Flows	133
	Condensed Consolidated Balance Sheets	134
	Condensed Consolidated Statements of Stockholder's Equity	136
	Management's Discussion and Analysis of Financial Condition and Results of Operations	137
	Notes to the Condensed Financial Statements	160
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	49
Item 4.	Controls and Procedures	49
	PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	230
Item 1A.	Risk Factors	230
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	230
	Signatures	233

4

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Table of Contents

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
Amended and Restated Loan Guarantee Agreement	Loan guarantee agreement entered into by Georgia Power with the DOE in 2014, as amended and restated on March 22, 2019, 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
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, the primary contractor for the remaining construction activities for Plant Vogtle Units 3 and 4
Bechtel Agreement	The October 23, 2017 construction completion agreement between the Vogtle Owners and Bechtel
CCR	Coal combustion residuals
CCR Rule	Disposal of Coal Combustion Residuals from Electric Utilities final rule published by the EPA in 2015
Chattanooga Gas	Chattanooga Gas Company, a wholly-owned subsidiary of Southern Company Gas
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
CPP	Clean Power Plan, the final action published by the EPA in 2015 that established guidelines for states to develop plans to meet EPA-mandated CO2 emission rates or emission reduction goals for existing electric generating units
Customer Refunds	Refunds issued to Georgia Power customers in 2018 as ordered by the Georgia PSC related to the Guarantee Settlement Agreement
CWIP	Construction work in progress
Dalton	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
Dalton Pipeline	A pipeline facility in Georgia in which Southern Company Gas has a 50% undivided ownership interest
DOE	U.S. Department of Energy
DSGP	Diamond State Generation Partners
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

5

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Table of Contents

DEFINITIONS

(continued)

Term	Meaning
Fitch	Fitch Ratings, Inc.
Form 10-K	Annual Report on Form 10-K of Southern Company, Alabama Power, Georgia Power, Mississippi Power, Southern Power, and Southern Company Gas for the year ended December 31, 2018, as applicable
GAAP	U.S. generally accepted accounting principles
Georgia Power	Georgia Power Company
GHG	Greenhouse gas
Guarantee Settlement Agreement	The June 9, 2017 settlement agreement between the Vogtle Owners and Toshiba related to certain payment obligations of the EPC Contractor guaranteed by Toshiba
Gulf Power	Gulf Power Company, until January 1, 2019, a subsidiary of Southern Company
Heating Degree Days	A measure of weather, calculated when the average daily temperatures are less than 65 degrees Fahrenheit
Heating Season	The period from November through March when Southern Company Gas' natural gas usage and operating revenues are generally higher
HLBV	Hypothetical liquidation at book value
IGCC	Integrated coal gasification combined cycle, the technology originally approved for Mississippi Power's Kemper County energy facility (Plant Ratcliffe)
IIC	Intercompany Interchange Contract
Illinois Commission	Illinois Commerce Commission
ITAAC	Inspections, Tests, Analyses, and Acceptance Criteria, standards established by the NRC
ITC	Investment tax credit
JEA	Jacksonville Electric Authority
KWH	Kilowatt-hour
LIFO	Last-in, first-out
LOCOM	Lower of weighted average cost or current market price
LTSA	Long-term service agreement
MEAG	Municipal Electric Authority of Georgia
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, and Elkton Gas as of June 30, 2018) (Nicor Gas, Atlanta Gas Light, Virginia Natural Gas, and Chattanooga Gas as of July 29, 2018)
NCCR	Georgia Power's Nuclear Construction Cost Recovery
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.
OATT	Open access transmission tariff
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

6

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Table of Contents

DEFINITIONS

(continued)

Term	Meaning
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
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
registrants	Southern Company, Alabama Power, Georgia Power, Mississippi Power, Southern Power Company, and Southern Company Gas
revenue from contracts with customers	Revenue from contracts accounted for under the guidance of ASC 606, Revenue from Contracts with Customers
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 Gas Dispositions	Southern Company Gas' disposition of Pivotal Home Solutions, Pivotal Utility Holdings' disposition of Elizabethtown Gas and Elkton Gas, and NUI Corporation's disposition of Pivotal Utility Holdings, which primarily consisted of Florida City 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
SP Solar	SP Solar Holdings I, LP
SP Wind	SP Wind Holdings II, LLC
Tax Reform Legislation	The Tax Cuts and Jobs Act, which became effective on January 1, 2018
Toshiba	Toshiba Corporation, the parent company of Westinghouse
traditional electric operating companies	Alabama Power, Georgia Power, Gulf Power, and Mississippi Power through December 31, 2018; Alabama Power, Georgia Power, and Mississippi Power as of January 1, 2019
Triton	Triton Container Investments, LLC
VCM	Vogtle Construction Monitoring

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DEFINITIONS

(continued)

Term	Meaning
VIE	Variable interest entity
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, MEAG, and Dalton
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

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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 business, customer and sales growth, economic conditions, fuel and environmental cost recovery and other rate actions, projected equity ratios, 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, matters related to the abandonment of the Kemper IGCC, completion of announced dispositions, filings with state and federal regulatory authorities, and estimated construction plans and expenditures. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "could," "would," "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 tax and environmental laws and regulations 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 extent and timing of costs and legal requirements related to CCR;

•	current and future litigation or regulatory investigations, proceedings, or inquiries, including litigation and other disputes related to the Kemper County energy facility;

•	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;

•	variations in demand for electricity and natural gas;

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

•	the ability to complete necessary or desirable pipeline expansion or infrastructure projects, limits on pipeline capacity, and operational interruptions to natural gas distribution and transmission activities;

•	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 only recently began initial operation in the global nuclear industry at this scale, and including changes in labor costs, availability, and productivity; challenges with management of contractors, subcontractors, or vendors; adverse weather conditions; shortages, delays, increased costs, or inconsistent quality of equipment, materials, and labor; contractor or supplier delay; nonperformance under construction, operating, or other agreements; operational readiness, including specialized operator training and required site safety programs; engineering or design problems; design and other licensing-based compliance matters, including the timely submittal by Southern Nuclear of the ITAAC documentation for each unit and the related reviews and approvals by the NRC necessary to support NRC authorization to load fuel; challenges with start-up activities, including major equipment failure, system integration, or regional transmission upgrades; 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 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 ROE, equity ratios, and fuel and other cost recovery mechanisms;

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

(continued)

•	the ability to successfully operate the electric utilities' generating, transmission, and distribution facilities and Southern Company Gas' natural gas distribution and storage facilities and the successful performance of necessary corporate functions;

•	legal proceedings and regulatory approvals and actions related to construction projects, such as Plant Vogtle Units 3 and 4 and pipeline projects, including PSC approvals and FERC and NRC actions;

•	under certain specified circumstances, a decision by holders of more than 10% of the ownership interests of Plant Vogtle Units 3 and 4 not to proceed with construction and the ability of other Vogtle Owners to tender a portion of their ownership interests to Georgia Power following certain construction cost increases;

•	in the event Georgia Power becomes obligated to provide funding to MEAG with respect to the portion of MEAG's ownership interest in Plant Vogtle Units 3 and 4 involving JEA, any inability of Georgia Power to receive repayment of such funding;

•	the inherent risks involved in operating and constructing nuclear generating facilities;

•	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 disposition of Plant Mankato, which cannot be assured to be completed or beneficial to Southern Company or its subsidiaries;

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

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

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

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

•	access to capital markets and other financing sources;

•	changes in Southern Company's and any of its subsidiaries' credit ratings;

•	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, 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.

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THE SOUTHERN COMPANY

AND SUBSIDIARY COMPANIES

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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,
	2019				2018				2019				2018
	(in millions)								(in millions)
Operating Revenues:
Retail electric revenues	$	3,540			$	3,740			$	6,623			$	7,308
Wholesale electric revenues	542				616				1,041				1,239
Other electric revenues	161				170				331				330
Natural gas revenues (includes alternative revenue programs of $1, $(4), $-, and $(27), respectively)	689				706				2,163				2,314
Other revenues	166				395				352				808
Total operating revenues	5,098				5,627				10,510				11,999
Operating Expenses:
Fuel	914				1,103				1,764				2,204
Purchased power	201				236				371				503
Cost of natural gas	191				228				877				949
Cost of other sales	84				279				203				568
Other operations and maintenance	1,316				1,523				2,628				2,972
Depreciation and amortization	755				783				1,506				1,552
Taxes other than income taxes	299				316				628				671
Estimated loss on plants under construction	4				1,060				6				1,105
(Gain) loss on dispositions, net	(8		)		36				(2,506		)		36
Total operating expenses	3,756				5,564				5,477				10,560
Operating Income	1,342				63				5,033				1,439
Other Income and (Expense):
Allowance for equity funds used during construction	31				32				63				63
Earnings from equity method investments	33				31				81				72
Interest expense, net of amounts capitalized	(429		)		(470		)		(859		)		(928		)
Other income (expense), net	99				78				176				138
Total other income and (expense)	(266		)		(329		)		(539		)		(655		)
Earnings (Loss) Before Income Taxes	1,076				(266		)		4,494				784
Income taxes (benefit)	145				(139		)		1,505				(25		)
Consolidated Net Income (Loss)	931				(127		)		2,989				809
Dividends on preferred stock of subsidiaries	3				4				7				8
Net income attributable to noncontrolling interests	29				23				—				17
Consolidated Net Income (Loss) Attributable to Southern Company	$	899			$	(154	)		$	2,982			$	784
Common Stock Data:
Earnings (loss) per share -
Basic	$	0.86			$	(0.15	)		$	2.86			$	0.77
Diluted	$	0.85			$	(0.15	)		$	2.84			$	0.77
Average number of shares of common stock outstanding (in millions)
Basic	1,044				1,014				1,041				1,012
Diluted	1,052				1,014				1,049				1,017

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

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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,
	2019				2018				2019				2018
	(in millions)								(in millions)
Consolidated Net Income (Loss)	$	931			$	(127	)		$	2,989			$	809
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(11), $(18), $(21), and $(3), respectively	(32		)		(54		)		(60		)		(8		)
Reclassification adjustment for amounts included in net income, net of tax of $(1), $21, $8, and $15, respectively	(3		)		64				24				45
Pension and other postretirement benefit plans:
Reclassification adjustment for amounts included in net income, net of tax of $-, $1, $-, and $1, respectively	—				2				1				4
Total other comprehensive income (loss)	(35		)		12				(35		)		41
Comprehensive Income (Loss)	896				(115		)		2,954				850
Dividends on preferred stock of subsidiaries	3				4				7				8
Comprehensive income attributable to noncontrolling interests	29				23				—				17
Consolidated Comprehensive Income (Loss) Attributable to Southern Company	$	864			$	(142	)		$	2,947			$	825

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

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

	For the Six Months Ended June 30,
	2019				2018
	(in millions)
Operating Activities:
Consolidated net income	$	2,989			$	809
Adjustments to reconcile consolidated net income to net cash provided from operating activities —
Depreciation and amortization, total	1,623				1,750
Deferred income taxes	274				(338		)
Allowance for equity funds used during construction	(63		)		(63		)
Mark-to-market adjustments	31				3
Pension, postretirement, and other employee benefits	(65		)		(74		)
Settlement of asset retirement obligations	(143		)		(97		)
Stock based compensation expense	75				83
Estimated loss on plants under construction	11				1,088
(Gain) loss on dispositions, net	(2,512		)		35
Impairment charges	32				161
Other, net	(22		)		(34		)
Changes in certain current assets and liabilities —
-Receivables	653				94
-Prepayments	(53		)		(73		)
-Natural gas for sale	255				295
-Other current assets	(18		)		(40		)
-Accounts payable	(1,045		)		(406		)
-Accrued taxes	938				213
-Accrued compensation	(312		)		(284		)
-Other current liabilities	(135		)		136
Net cash provided from operating activities	2,513				3,258
Investing Activities:
Property additions	(3,484		)		(3,828		)
Nuclear decommissioning trust fund purchases	(405		)		(571		)
Nuclear decommissioning trust fund sales	400				566
Proceeds from dispositions and asset sales	5,000				500
Cost of removal, net of salvage	(197		)		(128		)
Change in construction payables, net	(107		)		49
Investment in unconsolidated subsidiaries	(134		)		(63		)
Payments pursuant to LTSAs	(64		)		(103		)
Other investing activities	(7		)		(46		)
Net cash provided from (used for) investing activities	1,002				(3,624		)
Financing Activities:
Increase in notes payable, net	83				1,442
Proceeds —
Long-term debt	1,390				1,100
Common stock	452				222
Short-term borrowings	250				1,650
Redemptions and repurchases —
Long-term debt	(2,560		)		(3,379		)
Short-term borrowings	(1,850		)		(550		)
Distributions to noncontrolling interests	(82		)		(42		)
Capital contributions from noncontrolling interests	5				1,210
Payment of common stock dividends	(1,269		)		(1,194		)
Other financing activities	(67		)		(223		)
Net cash provided from (used for) financing activities	(3,648		)		236
Net Change in Cash, Cash Equivalents, and Restricted Cash	(133		)		(130		)
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	1,519				2,147
Cash, Cash Equivalents, and Restricted Cash at End of Period	$	1,386			$	2,017
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $36 and $35 capitalized for 2019 and 2018, respectively)	$	844			$	927
Income taxes, net	210				4
Noncash transactions — Accrued property additions at end of period	988				1,067

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

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

 

Assets		At June 30, 2019				At December 31, 2018
		(in millions)
Current Assets:
Cash and cash equivalents		$	1,383			$	1,396
Receivables —
Customer accounts receivable		1,654				1,726
Energy marketing receivables		361				801
Unbilled revenues		583				654
Under recovered fuel clause revenues		69				115
Other accounts and notes receivable		756				813
Accumulated provision for uncollectible accounts		(50		)		(50		)
Materials and supplies		1,440				1,465
Fossil fuel for generation		435				405
Natural gas for sale		268				524
Prepaid expenses		543				432
Assets from risk management activities, net of collateral		107				222
Other regulatory assets		607				525
Assets held for sale		58				393
Other current assets		138				162
Total current assets		8,352				9,583
Property, Plant, and Equipment:
In service		103,428				103,706
Less: Accumulated depreciation		30,693				31,038
Plant in service, net of depreciation		72,735				72,668
Nuclear fuel, at amortized cost		871				875
Construction work in progress		7,568				7,254
Total property, plant, and equipment		81,174				80,797
Other Property and Investments:
Goodwill		5,282				5,315
Equity investments in unconsolidated subsidiaries		1,557				1,580
Other intangible assets, net of amortization of $253 and $235 at June 30, 2019 and December 31, 2018, respectively		550				613
Nuclear decommissioning trusts, at fair value		1,942				1,721
Leveraged leases		813				798
Miscellaneous property and investments		505				269
Total other property and investments		10,649				10,296
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization		1,862				—
Deferred charges related to income taxes		794				794
Unamortized loss on reacquired debt		313				323
Regulatory assets – asset retirement obligations		4,062				2,933
Other regulatory assets, deferred		5,835				5,375
Assets held for sale, deferred		685				5,350
Other deferred charges and assets		1,141				1,463
Total deferred charges and other assets		14,692				16,238
Total Assets		$	114,867			$	116,914

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

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

 

Liabilities and Stockholders' Equity		At June 30, 2019				At December 31, 2018
		(in millions)
Current Liabilities:
Securities due within one year		$	3,148			$	3,198
Notes payable		1,398				2,915
Energy marketing trade payables		393				856
Accounts payable		1,978				2,580
Customer deposits		489				522
Accrued taxes —
Accrued income taxes		171				21
Other accrued taxes		501				635
Accrued interest		455				472
Accrued compensation		676				1,030
Asset retirement obligations		429				404
Other regulatory liabilities		304				376
Liabilities held for sale		36				425
Operating lease obligations		228				—
Other current liabilities		793				852
Total current liabilities		10,999				14,286
Long-term Debt		39,682				40,736
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		7,728				6,558
Deferred credits related to income taxes		6,386				6,460
Accumulated deferred ITCs		2,283				2,372
Employee benefit obligations		2,058				2,147
Operating lease obligations, deferred		1,702				—
Asset retirement obligations, deferred		9,478				8,990
Accrued environmental remediation		247				268
Other cost of removal obligations		2,283				2,297
Other regulatory liabilities, deferred		176				169
Liabilities held for sale, deferred		39				2,836
Other deferred credits and liabilities		384				465
Total deferred credits and other liabilities		32,764				32,562
Total Liabilities		83,445				87,584
Redeemable Preferred Stock of Subsidiaries		291				291
Total Stockholders' Equity (See accompanying statements)		31,131				29,039
Total Liabilities and Stockholders' Equity		$	114,867			$	116,914

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

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (UNAUDITED)

	Southern Company Common Stockholders' Equity
	Number of Common Shares						Common Stock																Accumulated Other Comprehensive Income (Loss)
	Issued			Treasury			Par Value				Paid-In Capital				Treasury				Retained Earnings								Noncontrolling Interests				Total
	(in millions)
Balance at December 31, 2017	1,009			(1	)		$	5,038			$	10,469			$	(36	)		$	8,885			$	(189	)		$	1,361			$	25,528
Consolidated net income attributable to Southern Company	—			—			—				—				—				938				—				—				938
Other comprehensive income	—			—			—				—				—				—				30				—				30
Stock issued	4			—			16				97				—				—				—				—				113
Stock-based compensation	—			—			—				36				—				—				—				—				36
Cash dividends of $0.58 per share	—			—			—				—				—				(586		)		—				—				(586		)
Contributions from noncontrolling interests	—			—			—				—				—				—				—				9				9
Distributions to noncontrolling interests	—			—			—				—				—				—				—				(13		)		(13		)
Net income (loss) attributable to noncontrolling interests	—			—			—				—				—				—				—				(6		)		(6		)
Other	—			—			—				1				(2		)		20				(41		)		(2		)		(24		)
Balance at March 31, 2018	1,013			(1	)		5,054				10,603				(38		)		9,257				(200		)		1,349				26,025
Consolidated net loss attributable to Southern Company	—			—			—				—				—				(154		)		—				—				(154		)
Other comprehensive income (loss)	—			—			—				—				—				—				12				—				12
Stock issued	2			—			12				97				—				—				—				—				109
Stock-based compensation	—			—			—				12				—				—				—				—				12
Cash dividends of $0.60 per share	—			—			—				—				—				(607		)		—				—				(607		)
Contributions from noncontrolling interests	—			—			—				—				—				—				—				22				22
Distributions to noncontrolling interests	—			—			—				—				—				—				—				(29		)		(29		)
Net income attributable to noncontrolling interests	—			—			—				—				—				—				—				23				23
Sale of noncontrolling interests	—			—			—				(407		)		—				—				—				1,690				1,283
Other	—			—			—				(2		)		(1		)		(2		)		—				1				(4		)
Balance at June 30, 2018	1,015			(1	)		$	5,066			$	10,303			$	(39	)		$	8,494			$	(188	)		$	3,056			$	26,692

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (UNAUDITED)

	Southern Company Common Stockholders' Equity
	Number of Common Shares						Common Stock																Accumulated Other Comprehensive Income (Loss)
	Issued			Treasury			Par Value				Paid-In Capital				Treasury				Retained Earnings								Noncontrolling Interests				Total
	(in millions)
Balance at December 31, 2018	1,035			(1	)		$	5,164			$	11,094			$	(38	)		$	8,706			$	(203	)		$	4,316			$	29,039
Consolidated net income attributable to Southern Company	—			—			—				—				—				2,084				—				—				2,084
Stock issued	6			—			28				196				—				—				—				—				224
Stock-based compensation	—			—			—				24				—				—				—				—				24
Cash dividends of $0.60 per share	—			—			—				—				—				(623		)		—				—				(623		)
Contributions from noncontrolling interests	—			—			—				—				—				—				—				3				3
Distributions to noncontrolling interests	—			—			—				—				—				—				—				(41		)		(41		)
Net income (loss) attributable to noncontrolling interests	—			—			—				—				—				—				—				(29		)		(29		)
Other	—			—			—				7				(2		)		—				—				1				6
Balance at March 31, 2019	1,041			(1	)		5,192				11,321				(40		)		10,167				(203		)		4,250				30,687
Consolidated net income attributable to Southern Company	—			—			—				—				—				899				—				—				899
Other comprehensive income	—			—			—				—				—				—				(35		)		—				(35		)
Stock issued	5			—			25				203				—				—				—				—				228
Stock-based compensation	—			—			—				11				—				—				—				—				11
Cash dividends of $0.62 per share	—			—			—				—				—				(646		)		—				—				(646		)
Contributions from noncontrolling interests	—			—			—				—				—				—				—				2				2
Distributions to noncontrolling interests	—			—			—				—				—				—				—				(47		)		(47		)
Net income attributable to noncontrolling interests	—			—			—				—				—				—				—				29				29
Other	—			—			—				5				(1		)		—				—				(1		)		3
Balance at June 30, 2019	1,046			(1	)		$	5,217			$	11,540			$	(41	)		$	10,420			$	(238	)		$	4,233			$	31,131

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

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SECOND QUARTER 2019 vs. SECOND QUARTER 2018

AND

YEAR-TO-DATE 2019 vs. YEAR-TO-DATE 2018

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 traditional electric operating companies are vertically integrated utilities providing electric service in three 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 and is involved in several other complementary businesses including gas pipeline investments, wholesale gas services, and gas marketing services. The Southern Company system's other business activities include providing energy solutions, such as distributed energy infrastructure and energy efficiency products and services, to customers. 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.

On January 1, 2019, Southern Company completed the sale of Gulf Power to NextEra Energy for an aggregate cash purchase price of approximately $5.8 billion (less $1.3 billion of indebtedness assumed), subject to customary working capital adjustments. The preliminary gain associated with the sale of Gulf Power totaled $2.5 billion pre-tax ($1.3 billion after tax). See Note (K) to the Condensed Financial Statements under "Southern Company" herein for additional information.

Georgia Power and Atlanta Gas Light each filed base rate cases with the Georgia PSC in June 2019. Georgia Power's filing includes a three-year Alternate Rate Plan with requested rate increases totaling $563 million, $145 million, and $234 million effective January 1, 2020, January 1, 2021, and January 1, 2022, respectively. Atlanta Gas Light's filing requests a $96 million increase in annual base rate revenues effective January 1, 2020. Nicor Gas filed a rate case with the Illinois Commission in November 2018, which was revised in April 2019, requesting an annual revenue increase of $180 million. These three rate cases are expected to conclude in 2019. In addition, Mississippi Power is scheduled to file a base rate case with the Mississippi PSC in the fourth quarter 2019. The ultimate outcome of these matters cannot be determined at this time. See FUTURE EARNINGS POTENTIAL – "Regulatory Matters" herein and Note 2 to the financial statements in Item 8 of the Form 10-K for additional information.

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.

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). Georgia Power holds a 45.7% ownership interest in Plant Vogtle Units 3 and 4. 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. The current expected in-service dates remain November 2021 for Unit 3 and November 2022 for Unit 4.

In the second quarter 2018, Georgia Power revised its base capital 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

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total project capital cost forecast of $8.4 billion (net of $1.7 billion received under the Guarantee Settlement Agreement and approximately $188 million in related Customer Refunds), with respect to Georgia Power's ownership interest.

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 were required to vote to continue construction. In September 2018, the Vogtle Owners unanimously voted to continue construction of Plant Vogtle Units 3 and 4. In connection with the vote to continue construction, Georgia Power entered into (i) a binding term sheet (Vogtle Owner Term Sheet) with the other Vogtle Owners and certain of MEAG's wholly-owned subsidiaries, including MEAG Power SPVJ, LLC (MEAG SPVJ), to take certain actions which partially mitigate potential financial exposure for the other Vogtle Owners and (ii) a term sheet (MEAG Term Sheet) with MEAG and MEAG SPVJ to provide funding with respect to MEAG SPVJ's ownership interest in Plant Vogtle Units 3 and 4 under certain circumstances. On January 14, 2019, Georgia Power, MEAG, and MEAG SPVJ entered into an agreement to implement the provisions of the MEAG Term Sheet. On February 18, 2019, Georgia Power, the other Vogtle Owners, and certain of MEAG's wholly-owned subsidiaries entered into certain amendments to their joint ownership agreements to implement the provisions of the Vogtle Owner Term Sheet.

In April 2019, Southern Nuclear completed a cost and schedule validation process to verify and update quantities of commodities remaining to install, labor hours to install remaining quantities and related productivity, testing and system turnover requirements, and forecasted staffing needs and related costs. This process confirmed the total estimated project capital cost forecast for Plant Vogtle Units 3 and 4. The expected in-service dates of November 2021 for Unit 3 and November 2022 for Unit 4, as previously approved by the Georgia PSC, remain unchanged.

In March 2019, Georgia Power entered into the Amended and Restated 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, up to approximately $5.130 billion. At June 30, 2019, Georgia Power had a total of $3.46 billion of borrowings outstanding under the related multi-advance credit facilities.

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

See FUTURE EARNINGS POTENTIAL – "Construction Program – Nuclear Construction" and Note (F) to the Condensed Financial Statements under "DOE Loan Guarantee Borrowings" herein for additional information.

RESULTS OF OPERATIONS

Net Income (Loss)

Second Quarter 2019 vs. Second Quarter 2018				Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)		(% change)		(change in millions)		(% change)
$1,053		N/M		$2,198		N/M

N/M - Not meaningful

Consolidated net income attributable to Southern Company was $899 million ($0.86 per share) for the second quarter 2019 compared to a net loss of $154 million ($(0.15) per share) for the corresponding period in 2018. The change was 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 and a decrease in operations and maintenance expenses.

Consolidated net income attributable to Southern Company was $3.0 billion ($2.86 per share) for year-to-date 2019 compared to $784 million ($0.77 per share) for the corresponding period in 2018. The increase was primarily due to the $2.5 billion ($1.3 billion after tax) gain on the sale of Gulf Power in 2019 and 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

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Plant Vogtle Units 3 and 4. See Note (K) to the Condensed Financial Statements under "Southern Company" herein and Note 2 to the financial statements under "Georgia Power – Nuclear Construction" in Item 8 of the Form 10-K for additional information.

Retail Electric Revenues

Second Quarter 2019 vs. Second Quarter 2018				Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)		(% change)		(change in millions)		(% change)
$(200)		(5.3)		$(685)		(9.4)

In the second quarter 2019, retail electric revenues were $3.5 billion compared to $3.7 billion for the corresponding period in 2018. For year-to-date 2019, retail electric revenues were $6.6 billion compared to $7.3 billion for the corresponding period in 2018.

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

		Second Quarter 2019							Year-to-Date 2019
		(in millions)				(% change)			(in millions)				(% change)
Retail electric – prior year		$	3,740						$	7,308
Estimated change resulting from –
Rates and pricing		125				3.3	%		182				2.5	%
Sales decline		(30		)		(0.8	)		(41		)		(0.6	)
Weather		34				0.9			(56		)		(0.8	)
Fuel and other cost recovery		(28		)		(0.7	)		(179		)		(2.4	)
Gulf Power disposition		(301		)		(8.0	)		(591		)		(8.1	)
Retail electric – current year		$	3,540			(5.3	)%		$	6,623			(9.4	)%

Revenues associated with changes in rates and pricing increased in the second quarter and year-to-date 2019 when compared to the corresponding periods in 2018 primarily due to increased revenues at Alabama Power due to the impacts of customer bill credits related to the Tax Reform Legislation in 2018 and increases to CNP Compliance revenue, increases in the NCCR tariff effective January 1, 2019 at Georgia Power, and increases in PEP and ECO Plan rates that became effective for the first billing cycle of September 2018 at Mississippi Power. The year-to-date 2019 increase also reflects the rate pricing effect of decreased customer usage, partially offset by lower contributions from commercial and industrial customers with variable demand-driven pricing at Georgia Power.

See Note 2 to the financial statements under "Alabama Power," "Georgia Power," and "Mississippi Power" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for additional information.

Revenues attributable to changes in sales decreased in the second quarter and year-to-date 2019 when compared to the corresponding periods in 2018. Weather-adjusted residential KWH sales decreased 1.0% and 0.3% in the second quarter and year-to-date 2019, respectively, when compared to the corresponding periods in 2018 primarily due to decreased customer usage primarily resulting from an increase in energy efficient residential appliances, partially offset by customer growth. Weather-adjusted commercial KWH sales decreased 1.3% and 1.6% in the second quarter and year-to-date 2019, respectively, when compared to the corresponding periods in 2018 primarily due to decreased customer usage resulting from an increase in energy saving initiatives. Industrial KWH sales decreased 2.0% in both the second quarter and year-to-date 2019 when compared to the corresponding periods in 2018 as a result of a decrease in demand resulting from changes in production levels primarily in the primary metals, chemicals, stone, clay, and glass, textile, and paper sectors.

Fuel and other cost recovery revenues decreased $28 million and $179 million in the second quarter and year-to-date 2019, respectively, compared to the corresponding periods in 2018 primarily due to decreases in generation and the average cost of fuel. The year-to-date decrease was also driven by milder weather in the first quarter 2019.

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Electric rates for the traditional electric operating companies include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the energy component of PPA costs, and do not affect net income. The traditional electric operating companies each have one or more regulatory mechanisms to recover other costs such as environmental and other compliance costs, storm damage, new plants, and PPA capacity costs.

Wholesale Electric Revenues

Second Quarter 2019 vs. Second Quarter 2018				Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)		(% change)		(change in millions)		(% change)
$(74)		(12.0)		$(198)		(16.0)

Wholesale electric revenues consist of PPAs 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, the 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.

In the second quarter 2019, wholesale electric revenues were $542 million compared to $616 million for the corresponding period in 2018. For year-to-date 2019, wholesale electric revenues were $1.0 billion compared to $1.2 billion for the corresponding period in 2018. The second quarter 2019 decrease was related to a $54 million decrease in energy revenues and a $20 million decrease in capacity revenues. The year-to-date 2019 decrease was related to a $160 million decrease in energy revenues and a $38 million decrease in capacity revenues. Excluding decreases of $7 million and $13 million of energy revenues for the second quarter and year-to-date 2019, respectively, related to the sale of Gulf Power, the decreases in energy revenues primarily related to Southern Power and included a decrease in non-PPA revenues due to a decrease in the volume of KWHs sold through short-term sales and a decrease in revenues from natural gas PPAs due to a decrease in the average cost of fuel and purchased power. These decreases were also due to lower fuel prices and lower customer demand at the traditional electric operating companies. The decreases in capacity revenues primarily related to the sales of Gulf Power and Southern Power's Plant Oleander and Plant Stanton Unit A in December 2018. See Note 15 to the financial statements under "Southern Power – Sales of Natural Gas Plants" in Item 8 of the Form 10-K for additional information.

Natural Gas Revenues

Second Quarter 2019 vs. Second Quarter 2018				Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)		(% change)		(change in millions)		(% change)
$(17)		(2.4)		$(151)		(6.5)

In the second quarter 2019, natural gas revenues were $689 million compared to $706 million for the corresponding period in 2018. For year-to-date 2019, natural gas revenues were $2.2 billion compared to $2.3 billion for the corresponding period in 2018.

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

	Second Quarter 2019							Year-to-Date 2019
	(in millions)				(% change)			(in millions)				(% change)
Natural gas revenues – prior year	$	706						$	2,314
Estimated change resulting from –
Infrastructure replacement programs and base rate changes	10				1.4	%		42				1.8	%
Gas costs and other cost recovery	(13		)		(1.8	)		49				2.1
Weather	(7		)		(1.1	)		—				—
Wholesale gas services	64				9.1			(16		)		(0.7	)
Southern Company Gas Dispositions	(70		)		(9.9	)		(237		)		(10.2	)
Other	(1		)		(0.1	)		11				0.5
Natural gas revenues – current year	$	689			(2.4	)%		$	2,163			(6.5	)%

Revenues attributable to infrastructure replacement programs and base rate changes at the natural gas distribution utilities increased in the second quarter and year-to-date 2019 compared to the corresponding periods in 2018 primarily due to increases of $4 million and $25 million, respectively, at Nicor Gas and $5 million and $14 million, respectively, at Atlanta Gas Light. These amounts include the natural gas distribution utilities' continued investments recovered through infrastructure replacement programs and base rate increases as well as increases due to the impacts of the Tax Reform Legislation.

Revenues attributable to gas costs and other cost recovery decreased in the second quarter 2019 and increased year-to-date 2019 compared to the corresponding periods in 2018. The decrease in the second quarter 2019 is primarily due to lower natural gas prices and decreased volumes of natural gas sold. The increase for year-to-date 2019 is primarily due to increased natural gas prices in the first quarter 2019, partially offset by decreased volumes of natural gas sold year-to-date 2019. 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 the natural gas distribution utilities.

Revenues decreased in the second quarter 2019 due to warmer weather, as determined by Heating Degree Days, in Illinois and Georgia compared to the corresponding period in 2018.

Revenues attributable to Southern Company Gas' wholesale gas services business increased in the second quarter 2019 and decreased year-to-date 2019 compared to the corresponding periods in 2018. The increase in the second quarter 2019 is primarily due to derivative gains, partially offset by decreased commercial activity. For year-to-date 2019, the decrease is primarily due to decreased commercial activity, partially offset by derivative gains.

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

Other Revenues

Second Quarter 2019 vs. Second Quarter 2018				Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)		(% change)		(change in millions)		(% change)
$(229)		(58.0)		$(456)		(56.4)

In the second quarter 2019, other revenues were $166 million compared to $395 million for the corresponding period in 2018. For year-to-date 2019, other revenues were $352 million compared to $808 million for the corresponding period in 2018. These decreases were primarily related to PowerSecure's 2018 storm restoration services in Puerto Rico.

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Fuel and Purchased Power Expenses

	Second Quarter 2019 vs. Second Quarter 2018						Year-to-Date 2019 vs. Year-to-Date 2018
	(change in millions)				(% change)		(change in millions)				(% change)
Fuel	$	(189	)		(17.1)		$	(440	)		(20.0)
Purchased power	(35		)		(14.8)		(132		)		(26.2)
Total fuel and purchased power expenses	$	(224	)				$	(572	)

In the second quarter 2019, total fuel and purchased power expenses were $1.1 billion compared to $1.3 billion for the corresponding period in 2018. Excluding approximately $126 million associated with the sale of Gulf Power, the decrease was primarily the result of an $81 million decrease in the average cost of fuel and purchased power and a $17 million net decrease in the aggregate volume of KWHs generated and purchased.

For year-to-date 2019, total fuel and purchased power expenses were $2.1 billion compared to $2.7 billion for the corresponding period in 2018. Excluding approximately $225 million associated with the sale of Gulf Power, the decrease was primarily the result of a $198 million decrease in the average cost of fuel and purchased power and a $149 million decrease in the aggregate volume of KWHs generated and purchased.

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

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

	Second Quarter 2019		Second Quarter 2018(a)		Year-to-Date 2019		Year-to-Date 2018(a)
Total generation (in billions of KWHs)	46		47		90		93
Total purchased power (in billions of KWHs)	4		4		8		7
Sources of generation (percent) —
Gas	52		45		50		45
Coal	22		29		22		29
Nuclear	16		15		16		16
Hydro	3		3		5		3
Other	7		8		7		7
Cost of fuel, generated (in cents per net KWH)—
Gas	2.39		2.71		2.47		2.78
Coal	3.04		2.71		2.98		2.80
Nuclear	0.80		0.82		0.80		0.80
Average cost of fuel, generated (in cents per net KWH)	2.26		2.39		2.29		2.43
Average cost of purchased power (in cents per net KWH)(b)	4.89		5.18		5.04		6.11

(a)	Excludes Gulf Power, which was sold on January 1, 2019.

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

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Fuel

In the second quarter 2019, fuel expense was $0.9 billion compared to $1.1 billion for the corresponding period in 2018. Excluding approximately $74 million related to Gulf Power in 2018, the decrease was primarily due to a 26.2% decrease in the volume of KWHs generated by coal and an 11.8% decrease in the average cost of natural gas per KWH generated, partially offset by a 12.2% increase in the average cost of coal per KWH generated and a 12.1% increase in the volume of KWHs generated by natural gas.

For year-to-date 2019, fuel expense was $1.8 billion compared to $2.2 billion for the corresponding period in 2018. Excluding approximately $127 million related to Gulf Power in 2018, the decrease was primarily due to a 27.6% decrease in the volume of KWHs generated by coal and an 11.2% decrease in the average cost of natural gas per KWH generated, partially offset by a 6.6% increase in the volume of KWHs generated by natural gas and a 6.4% increase in the average cost of coal per KWH generated.

Purchased Power

In the second quarter 2019, purchased power expense was $201 million compared to $236 million for the corresponding period in 2018. This decrease was primarily associated with Gulf Power.

For year-to-date 2019, purchased power expense was $371 million compared to $503 million for the corresponding period in 2018. Excluding approximately $98 million associated with Gulf Power, the decrease was primarily due to a 17.5% decrease in the average cost per KWH purchased and a 2.1% decrease in the volume of KWHs purchased.

See Note (K) to the Condensed Financial Statements under "Southern Company" herein for information regarding the sale of Gulf Power.

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.

Cost of Natural Gas

Second Quarter 2019 vs. Second Quarter 2018				Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)		(% change)		(change in millions)		(% change)
$(37)		(16.2)		$(72)		(7.6)

Excluding Atlanta Gas Light, which does not sell natural gas to end-use customers, 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 the natural gas distribution utilities. Cost of natural gas at the natural gas distribution utilities represented 80% and 85% of total cost of natural gas for the second quarter and year-to-date 2019, respectively.

In the second quarter 2019, cost of natural gas was $191 million compared to $228 million for the corresponding period in 2018. Excluding a $25 million decrease related to the Southern Company Gas Dispositions, cost of natural gas decreased $12 million.

For year-to-date 2019, cost of natural gas was $877 million compared to $949 million for the corresponding period in 2018. Excluding a $104 million decrease related to the Southern Company Gas Dispositions, cost of natural gas increased $32 million. This increase reflects an increase in natural gas prices, partially offset by a decrease in the volume of natural gas sold year-to-date 2019 compared to the corresponding period in 2018.

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Cost of Other Sales

Second Quarter 2019 vs. Second Quarter 2018				Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)		(% change)		(change in millions)		(% change)
$(195)		(69.9)		$(365)		(64.3)

In the second quarter 2019, cost of other sales was $84 million compared to $279 million for the corresponding period in 2018. For year-to-date 2019, cost of other sales was $203 million compared to $568 million for the corresponding period in 2018. These decreases were primarily related to PowerSecure's 2018 storm restoration services in Puerto Rico.

Other Operations and Maintenance Expenses

Second Quarter 2019 vs. Second Quarter 2018				Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)		(% change)		(change in millions)		(% change)
$(207)		(13.6)		$(344)		(11.6)

In the second quarter 2019, other operations and maintenance expenses were $1.3 billion compared to $1.5 billion for the corresponding period in 2018. For year-to-date 2019, other operations and maintenance expenses were $2.6 billion compared to $3.0 billion for the corresponding period in 2018. The second quarter and year-to-date 2019 decreases reflect approximately $90 million and $166 million, respectively, related to Gulf Power in 2018 and $34 million and $105 million, respectively, related to the Southern Company Gas Dispositions. These decreases also reflect an asset impairment charge of $119 million recorded in the second quarter 2018 at Southern Power related to the sale of Southern Power's Florida plants. These decreases were partially offset by a $32 million goodwill impairment charge in the second quarter 2019 in contemplation of the sale of PowerSecure's utility infrastructure services business unit. See Note (K) to the Condensed Financial Statements under "Southern Company" herein and Note 15 to the financial statements under "Southern Power" and "Southern Company Gas" in Item 8 of the Form 10-K for additional information.

Depreciation and Amortization

Second Quarter 2019 vs. Second Quarter 2018				Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)		(% change)		(change in millions)		(% change)
$(28)		(3.6)		$(46)		(3.0)

In the second quarter 2019, depreciation and amortization was $755 million compared to $783 million for the corresponding period in 2018. For year-to-date 2019, depreciation and amortization was $1.5 billion compared to $1.6 billion for the corresponding period in 2018. The second quarter and year-to-date 2019 decreases were primarily due to decreases of $48 million and $95 million, respectively, related to the sale of Gulf Power and decreases of $10 million and $26 million, respectively, related to the Southern Company Gas Dispositions, partially offset by increases of $29 million and $62 million, respectively, related to additional plant in service.

Taxes Other Than Income Taxes

Second Quarter 2019 vs. Second Quarter 2018				Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)		(% change)		(change in millions)		(% change)
$(17)		(5.4)		$(43)		(6.4)

In the second quarter 2019, taxes other than income taxes were $299 million compared to $316 million for the corresponding period in 2018. For year-to-date 2019, taxes other than income taxes were $628 million compared to $671 million for the corresponding period in 2018. These decreases primarily relate to the sale of Gulf Power.

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Estimated Loss on Plants Under Construction

Second Quarter 2019 vs. Second Quarter 2018				Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)		(% change)		(change in millions)		(% change)
$(1,056)		(99.6)		$(1,099)		(99.5)

In the second quarter 2019, estimated loss on plants under construction was $4 million compared to $1.06 billion for the corresponding period in 2018. For year-to-date 2019, estimated loss on plants under construction was $6 million compared to $1.11 billion for the corresponding period in 2018. These decreases were primarily due to the $1.1 billion charge recorded in the second quarter 2018 as a result of Georgia Power's revised estimate to complete construction and start-up of Plant Vogtle Units 3 and 4. The second quarter and year-to-date 2019 charges were related to abandonment and closure activities for the mine and gasifier-related assets of the Kemper IGCC at Mississippi Power.

See Note 2 to the financial statements in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein under "Georgia Power – Nuclear Construction" for additional information.

(Gain) Loss on Dispositions, Net

Second Quarter 2019 vs. Second Quarter 2018				Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)		(% change)		(change in millions)		(% change)
$44		N/M		$2,542		N/M

N/M - Not meaningful

In the second quarter 2019, gain on dispositions, net was $8 million compared to a loss on dispositions, net of $36 million in the corresponding period in 2018. This change was primarily due to a $36 million loss on the sale of Pivotal Home Solutions at Southern Company Gas recorded in 2018 and a $23 million gain as a result of the sale of Southern Power's Plant Nacogdoches in the second quarter 2019, partially offset by a $15 million adjustment to the preliminary gain on the sale of Gulf Power.

For year-to-date 2019, gain on dispositions, net was $2.5 billion compared to a loss on dispositions, net of $36 million in the corresponding period in 2018. This change was primarily due to a preliminary gain of $2.5 billion ($1.3 billion after tax) on the sale of Gulf Power.

See Note (K) to the Condensed Financial Statements under "Southern Company" herein for additional information.

Interest Expense, Net of Amounts Capitalized

Second Quarter 2019 vs. Second Quarter 2018				Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)		(% change)		(change in millions)		(% change)
$(41)		(8.7)		$(69)		(7.4)

In the second quarter 2019, interest expense, net of amounts capitalized was $429 million compared to $470 million in the corresponding period in 2018. For year-to-date 2019, interest expense, net of amounts capitalized was $859 million compared to $928 million in the corresponding period in 2018. Excluding decreases of $13 million and $26 million in the second quarter and year-to-date 2019, respectively, related to the sale of Gulf Power, the decreases were primarily due to a decrease in average outstanding long-term debt, primarily at the parent company.

See FINANCIAL CONDITION AND LIQUIDITY – "Financing Activities" herein, Note 8 to the financial statements in Item 8 of the Form 10-K, and Note (F) to the Condensed Financial Statements herein for additional information.

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Other Income (Expense), Net

Second Quarter 2019 vs. Second Quarter 2018				Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)		(% change)		(change in millions)		(% change)
$21		26.9		$38		27.5

In the second quarter 2019, other income (expense), net was $99 million compared to $78 million for the corresponding period in 2018. For year-to-date 2019, other income (expense), net was $176 million compared to $138 million for the corresponding period in 2018. These increases were primarily due to a $36 million gain arising from the settlement of litigation related to the Roserock solar facility at Southern Power in June 2019, partially offset by $24 million due to the settlement of Mississippi Power's Deepwater Horizon claim in May 2018. Also contributing to these increases were $7 million and $13 million for the second quarter and year-to-date 2019, respectively, of non-service cost-related pension income and $10 million for year-to-date 2019 of increased interest income from temporary cash investments at the parent company. See Note (C) to the Condensed Financial Statements under "General Litigation Matters – Southern Power" herein and Note 3 to the financial statements under "Other Matters – Mississippi Power," in Item 8 of the Form 10-K for additional information.

Income Taxes (Benefit)

Second Quarter 2019 vs. Second Quarter 2018				Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)		(% change)		(change in millions)		(% change)
$284		N/M		$1,530		N/M

N/M - Not meaningful

In the second quarter 2019, income taxes were $145 million compared to an income tax benefit of $139 million for the corresponding period in 2018. The change was primarily due to the reduction in pre-tax earnings in the second quarter 2018 resulting from the charge associated with Plant Vogtle Units 3 and 4 construction.

For year-to-date 2019, income taxes were $1.5 billion compared to an income tax benefit of $25 million for the corresponding period in 2018. The change was primarily due to the tax impacts related to the sale of Gulf Power and the reduction in pre-tax earnings in the second quarter 2018 resulting from the charge associated with Plant Vogtle Units 3 and 4 construction.

See Notes (G) and (K) to the Condensed Financial Statements herein for additional information.

Net Income Attributable to Noncontrolling Interests

Second Quarter 2019 vs. Second Quarter 2018				Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)		(% change)		(change in millions)		(% change)
$6		26.1		$(17)		N/M

N/M - Not meaningful

Substantially all noncontrolling interests relate to renewable projects at Southern Power. See Notes 1 and 7 to the financial statements in Item 8 of the Form 10-K under "General" and "Southern Power," respectively, for additional information.

In the second quarter 2019, net income attributable to noncontrolling interests was $29 million compared to $23 million for the corresponding period in 2018. The increase was primarily due to an allocation of approximately $26 million of income to the noncontrolling interest partner related to the Roserock solar facility litigation settlement, partially offset by $25 million of losses attributable to noncontrolling interests related to the tax equity partnerships entered into in 2018.

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For year-to-date 2019, net income attributable to noncontrolling interests was immaterial compared to $17 million for the corresponding period in 2018. The decrease was primarily due to $48 million of losses attributable to noncontrolling interests related to the tax equity partnerships entered into in 2018, partially offset by an allocation of approximately $29 million of income to the noncontrolling interest partner related to the Roserock solar facility litigation settlement.

FUTURE EARNINGS POTENTIAL

The results of operations discussed above are not necessarily indicative of Southern Company's future earnings potential. Future earnings will be impacted by the recently completed and additional pending disposition activities described herein, in Note (K) to the Condensed Financial Statements herein, and in Note 15 to the financial statements in Item 8 of the Form 10-K. 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 constructive regulatory environments that allow for the timely recovery of prudently-incurred costs during a time of increasing costs, continued customer growth, and, for the traditional electric operating companies, the weak pace of growth in electricity use per customer, especially in residential and commercial markets. Plant Vogtle Units 3 and 4 construction and rate recovery and the profitability of Southern Power's competitive wholesale business are also major factors.

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, the development or acquisition of renewable facilities and other 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.

On June 13, 2019, Southern Power completed the sale of its equity interests in Nacogdoches Power, LLC, the owner of an approximately 115-MW biomass facility located in Nacogdoches County, Texas, to Austin Energy, for an aggregate cash purchase price of approximately $461 million, including working capital adjustments.

On May 4, 2019, Southern Power achieved commercial operation of the 385-MW natural gas expansion unit at Plant Mankato and started providing energy under a PPA with Northern States Power on June 1, 2019. The sale of Plant Mankato to Northern States Power remains subject to state commission approvals and is expected to close in fall 2019. If these state commission approvals are not obtained by October 1, 2019, either party has the option to

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terminate the sale, which, if elected, would result in the payment of a $15 million termination fee by Northern States Power to Southern Power. The ultimate outcome of this matter cannot be determined at this time.

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

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 GHG strategies to assess upcoming requirements and compliance costs associated with these environmental laws and regulations and to achieve stated goals. Related costs may result from the installation of additional environmental controls, closure and monitoring of CCR facilities, unit retirements, or changing fuel sources for certain existing units, as well as related upgrades to the Southern Company system's transmission and distribution (electric and natural gas) systems, and may impact future electric generating unit retirement and replacement decisions, results of operations, cash flows, and/or financial condition. A major portion of these costs is expected to be recovered through retail and wholesale rates. The ultimate impact of environmental laws and regulations and GHG goals will depend on various factors, such as state adoption and implementation of requirements, the availability and cost of any deployed technology, fuel prices, 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 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/or 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 under "Environmental Matters" in Item 8 of the Form 10-K for additional information.

Environmental Laws and Regulations

Coal Combustion Residuals

In June 2019, Alabama Power recorded an increase of approximately $308 million to its AROs primarily related to the CCR Rule and the related state rule based on management's completion of closure designs during the second quarter 2019 for all but two of its ash pond facilities, including one jointly owned with Mississippi Power. The additional estimated costs to close these ash ponds under the planned closure-in-place methodology primarily relate to cost inputs from contractor bids, internal drainage and dewatering system designs, and increases in the estimated ash volumes. The cost estimate for the remaining ash pond facilities will be updated within the next 12 months and the change could be material.

As further analysis is performed and additional details are developed with respect to ash pond closures, the traditional electric operating companies expect to periodically update their ARO cost estimates. Additionally, the closure designs and plans in the States of Alabama and Georgia are subject to approval by environmental regulatory agencies. Absent continued recovery of ARO costs through regulated rates, Southern Company'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. See Note 6 to the financial statements in Item 8 of the Form 10-K and Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information.

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Global Climate Issues

On July 8, 2019, the EPA published the final Affordable Clean Energy rule (ACE Rule) to repeal and replace the CPP. Implementation of the CPP has been stayed by the U.S. Supreme Court since 2016. The ACE Rule requires states to develop unit-specific CO₂ emission rate standards for existing coal-fired units based on heat-rate efficiency improvements. Combustion turbines, including natural gas combined cycles, are not included as affected sources in the ACE Rule. The Southern Company system has ownership interests in 19 coal-fired units to which the ACE Rule is applicable. The ultimate impact of the ACE Rule, including the repeal and replacement of the CPP, to the Southern Company system will depend on state implementation plan requirements and the outcome of any associated legal challenges and cannot be determined at this time.

Regulatory Matters

See Note 2 to the financial statements in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for additional information.

Fuel Cost Recovery

The traditional electric operating companies each have established fuel cost recovery rates approved by their respective state PSCs. Fuel cost recovery revenues are adjusted for differences in actual recoverable fuel costs and 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.

Environmental Accounting Order

On April 15, 2019, Alabama Power retired Plant Gorgas Units 8, 9, and 10 and reclassified approximately $654 million of the unrecovered asset balances to regulatory assets, which are being recovered over the units' remaining useful lives, the latest being through 2037, as established prior to the decision to retire. Additionally, approximately $700 million of net capitalized asset retirement costs were reclassified to a regulatory asset in accordance with accounting guidance provided by the Alabama PSC. The asset retirement costs are being recovered through 2055. See Note 2 to the financial statements under "Alabama Power – Environmental Accounting Order" and Note 6 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 (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.

Rate Plans

On June 28, 2019, Georgia Power filed a base rate case (Georgia Power 2019 Base Rate Case) with the Georgia PSC. The filing includes a three-year Alternate Rate Plan with requested rate increases totaling $563 million, $145 million, and $234 million effective January 1, 2020, January 1, 2021, and January 1, 2022, respectively. These

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increases are based on a proposed retail ROE of 10.90% and a proposed equity ratio of 56% and reflect levelized revenue requirements during the three-year period, with the exception of incremental compliance costs related to CCR AROs, Demand-Side Management programs, and adjustments to the Municipal Franchise Fee tariff.

Georgia Power has requested recovery of the proposed increases through its existing base rate tariffs as follows:

Tariff	2020			2021			2022
	(in millions)
Traditional base:
Levelized	$	209		$	—		$	—
CCR AROs	158			140			227
ECCR	165			—			—
Demand-Side Management	14			2			1
Municipal Franchise Fee	17			3			5
Total(*)	$	563		$	145		$	234

(*)	Totals may not add due to rounding.

Georgia Power's filing primarily reflects requests to (i) address the impacts of the Tax Reform Legislation, (ii) recover the costs of recent and future capital investments in infrastructure designed to maintain high levels of reliability and superior customer service with updated depreciation rates, (iii) recover substantial storm damage expenses incurred and deferred since 2013 along with a reasonable level of storm damage expenses expected to be incurred during the three years ending December 31, 2022, and (iv) recover the costs necessary to comply with federal and state regulations for CCR AROs. In addition, the filing includes the following provisions:

•	Continuation of an allowed retail ROE range of 10.00% to 12.00%.

•	Continuation of the process whereby two-thirds of any earnings above the top of the allowed ROE range are shared with Georgia Power's customers and the remaining one-third are retained by Georgia Power.

•	Continuation of the option to file an Interim Cost Recovery tariff in the event earnings are projected to fall below the bottom of the ROE range during the three-year term of the plan.

Georgia Power expects the Georgia PSC to issue a final order in this matter on December 17, 2019. The ultimate outcome of this matter cannot be determined at this time.

Integrated Resource Plan

In 2016, the Georgia PSC approved Georgia Power's triennial Integrated Resource Plan, including recovery of costs up to $99 million through June 30, 2019 to preserve nuclear generation as an option at a future generation site in Stewart County, Georgia. In 2017, the Georgia PSC approved Georgia Power's decision to suspend work at the site due to changing economics, including lower load forecasts and fuel costs. In accordance with the Georgia PSC's order, costs incurred of approximately $50 million have been recorded as a regulatory asset.

On July 16, 2019, the Georgia PSC voted to approve Georgia Power's triennial Integrated Resource Plan (2019 IRP) as modified by a stipulated agreement among Georgia Power, the staff of the Georgia PSC, and certain intervenors and further modified by the Georgia PSC.

In the 2019 IRP, the Georgia PSC approved the decertification and retirement of Plant Hammond Units 1 through 4 (840 MWs) and Plant McIntosh Unit 1 (142.5 MWs) effective July 29, 2019. The Georgia PSC also approved the reclassification of the remaining net book values of the Plant Hammond and Plant McIntosh units (approximately $500 million and $40 million, respectively, at June 30, 2019), as well as any unusable materials and supplies inventory balances, upon retirement to a regulatory asset. Recovery of each unit's net book value will continue through December 31, 2019 as provided in the 2013 ARP.

For the regulatory asset balances remaining at December 31, 2019, Georgia Power requested recovery in the Georgia Power 2019 Base Rate Case as follows: (i) the net book values of Plant Mitchell Unit 3 (approximately $8

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million at June 30, 2019) and Plant McIntosh Unit 1, any unusable materials and supplies inventory, and the future generation site in Stewart County, Georgia over a three-year period ending December 31, 2022 and (ii) the net book values of Plant Hammond Units 1 through 4 over a period equal to the applicable unit's remaining useful life through 2035. The ultimate outcome of these matters cannot be determined at this time.

Also in the 2019 IRP, the Georgia PSC rejected a request to certify approximately 25 MWs of capacity at Plant Scherer Unit 3 for the retail jurisdiction beginning January 1, 2020 following the expiration of a wholesale PPA. Georgia Power may offer such capacity in the wholesale market or to the retail jurisdiction in a future Integrated Resource Plan. The ultimate outcome of this matter cannot be determined at this time but is not expected to have a material impact on Southern Company's financial statements.

Additionally, the Georgia PSC approved Georgia Power's proposed environmental compliance strategy associated with ash pond and certain landfill closures and post-closure care in compliance with the CCR Rule and the related state rule. In the Georgia Power 2019 Base Rate Case, Georgia Power requested recovery of the under recovered balance of these compliance costs at December 31, 2019 (approximately $135 million at June 30, 2019) over a three-year period ending December 31, 2022 and recovery of estimated compliance costs of $277 million for 2020, $395 million for 2021, and $655 million for 2022 over three-year periods ending December 31, 2022, 2023, and 2024, respectively. The ultimate outcome of this matter cannot be determined at this time. See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information regarding Georgia Power's AROs.

The Georgia PSC also approved Georgia Power to (i) issue requests for proposals (RFP) for capacity beginning in 2022 or 2023 and in 2026, 2027, or 2028; (ii) procure up to an additional 2,210 MWs of renewable resources through competitive RFPs; and (iii) invest in a portfolio of up to 80 MWs of battery energy storage technologies.

See "Rate Plans" herein for additional information regarding the Georgia Power 2019 Base Rate Case.

Mississippi Power

Kemper County Energy Facility

As the mining permit holder, Liberty Fuels Company, LLC has a legal obligation to perform mine reclamation, and Mississippi Power has a contractual obligation to fund all reclamation activities. As a result of the abandonment of the Kemper IGCC, final mine reclamation began in 2018 and is expected to be substantially completed in 2020, with monitoring expected to continue through 2027. See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information.

During the second quarter and year-to-date 2019, Mississippi Power recorded pre-tax charges to income of $4 million ($3 million after tax) and $6 million ($5 million after tax), respectively, primarily resulting from the abandonment and related closure activities and ongoing period costs, net of sales proceeds, 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 at up to $10 million pre-tax (excluding dismantlement costs, net of salvage), may be incurred through the first half of 2020. 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 $7 million for the remainder of 2019 and $2 million to $6 million annually in 2020 through 2023.

In addition, Mississippi Power constructed the CO₂ pipeline for the planned transport of captured CO₂ for use in enhanced oil recovery and is currently evaluating its options regarding the final disposition of the CO₂ pipeline, including removal of the pipeline. This evaluation is expected to be complete later in 2019. If Mississippi Power ultimately decides to remove the CO₂ pipeline, the cost of removal could have a material impact on Southern Company's financial statements.

In December 2018, Mississippi Power filed with the DOE its request for property closeout certification under the contract related to the $387 million of grants received. Mississippi Power and the DOE are currently in discussions regarding the requested closeout and property disposition, which may require payment to the DOE for a portion of certain property that is to be retained by Mississippi Power. In connection with the DOE closeout discussions, on April 29, 2019, the Civil Division of the Department of Justice informed Southern Company and Mississippi Power

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of an investigation related to the Kemper County energy facility. The ultimate outcome of these matters cannot be determined at this time; however, they could have a material impact on Southern Company's financial statements.

Southern Company Gas

The natural gas distribution utilities are subject to regulation and oversight by their respective state regulatory agencies for the rates charged to their customers and other matters. With the exception of Atlanta Gas Light, which does not sell natural gas to end-use customers, the natural gas distribution utilities are authorized by the relevant regulatory agencies in the states in which they serve to use natural gas cost recovery mechanisms that adjust rates to reflect changes in the wholesale cost of natural gas and ensure recovery of all costs prudently incurred in purchasing natural gas for customers. 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 revenues or net income, but will affect cash flows. In addition to natural gas cost recovery mechanisms, there are other cost recovery mechanisms, such as regulatory riders, which vary by utility but allow recovery of certain costs, such as those related to infrastructure replacement programs, as well as environmental remediation and energy efficiency plans.

In November 2018, Nicor Gas filed a general base rate case with the Illinois Commission requesting a $230 million increase in annual base rate revenues. The requested increase is based on a projected test year for the 12-month period ending September 30, 2020, a ROE of 10.6%, and an increase in the equity ratio from 52% to 54% to address the negative cash flow and credit metric impacts of the Tax Reform Legislation.

On April 16, 2019, Nicor Gas entered into a stipulation agreement to resolve all related issues with the Staff of the Illinois Commission, including a ROE of 9.86% and an equity ratio of 54%. Also on April 16, 2019, Nicor Gas filed its rebuttal testimony with the Illinois Commission incorporating the stipulation agreement and addressing the remaining items outstanding with the other two intervenors. As a result of the stipulation agreement and rebuttal testimony, the revised requested annual revenue increase is $180 million.

The Illinois Commission is expected to rule on the requested increase by early October 2019, after which rate adjustments will be effective.

On June 3, 2019, Atlanta Gas Light filed a general base rate case with the Georgia PSC requesting a $96 million increase in annual base rate revenues. The requested increase is based on a forward-looking test year for the 12-month period ending July 31, 2020, a ROE of 10.75% with an earnings band based on a ROE between 10.55% and 10.95%, and a continued equity ratio of 55%. The filing also requests the continuation of the Georgia rate adjustment mechanism, as previously authorized. Atlanta Gas Light expects the Georgia PSC to issue a final order on this matter on December 19, 2019 with the new rates becoming effective January 1, 2020.

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

Construction Program

Overview

The subsidiary companies of Southern Company are engaged in continuous construction programs to accommodate existing and estimated future loads on their respective systems. The Southern Company system intends to continue its strategy of developing and constructing new electric generating facilities, adding environmental modifications to certain existing units, expanding and improving 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 2 and

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15 to the financial statements under "Southern Company Gas – Infrastructure Replacement Programs and Capital Projects" and "Southern Power," respectively, in Item 8 of the Form 10-K and Note (K) 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 2 to the financial statements under "Georgia Power – 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 2 to the financial statements under "Georgia Power – Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding the construction of Plant Vogtle Units 3 and 4, the joint ownership agreements and related funding agreement, VCM reports, and the NCCR tariff.

In 2009, the Georgia PSC certified construction of Plant Vogtle Units 3 and 4. Georgia Power holds a 45.7% ownership interest in 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 other Vogtle Owners, entered into several transitional arrangements to allow construction to continue. In July 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into the Vogtle Services Agreement, whereby 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 provides that it 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, executed the Bechtel Agreement, 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.

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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, 2019(b)	(5.2		)
Remaining estimate to complete(a)	$	3.2

(a)	Excludes financing costs expected to be capitalized through AFUDC of approximately $315 million.

(b)	Net of $1.7 billion received from Toshiba under the Guarantee Settlement Agreement and approximately $188 million in related Customer Refunds.

Georgia Power estimates that its financing costs for construction of Plant Vogtle Units 3 and 4 will total approximately $3.1 billion, of which $2.0 billion had been incurred through June 30, 2019.

In April 2019, Southern Nuclear completed a cost and schedule validation process to verify and update quantities of commodities remaining to install, labor hours to install remaining quantities and related productivity, testing and system turnover requirements, and forecasted staffing needs and related costs. This process confirmed the estimated total project capital cost forecast for Plant Vogtle Units 3 and 4. The expected in-service dates of November 2021 for Unit 3 and November 2022 for Unit 4, as previously approved by the Georgia PSC, remain unchanged.

As construction continues and testing and system turnover activities increase, challenges with management of contractors, subcontractors, and vendors; supervision of craft labor and related craft labor productivity, ability to attract and retain craft labor, and/or related cost escalation; procurement, fabrication, delivery, assembly, and/or installation and the initial testing and start-up, including any required engineering changes, of plant systems, structures, or components (some of which are based on new technology that only recently began initial operation in the global nuclear industry at this scale), or regional transmission upgrades, any of which may require additional labor and/or materials; or other issues could arise and change the projected schedule and estimated cost.

The April 2019 cost and schedule validation process established target values for monthly construction production and system turnover activities as part of a strategy to maintain and, where possible, build margin to the approved in-service dates. To support that strategy, monthly production and activity target values will continue to increase significantly throughout 2019. To meet these increasing monthly targets, existing craft construction productivity must improve and additional craft laborers (particularly electrical and pipefitter craft labor), as well as additional supervision and other field support resources, must be retained and deployed.

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 submittal by Southern Nuclear of the ITAAC documentation for each unit and the related reviews and approvals by the NRC necessary to support NRC authorization to load fuel, 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 regulatory-approved project schedule is currently estimated to result in additional base capital costs of approximately $50

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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 to provide for, among other conditions, additional Vogtle Owner approval requirements. Effective in August 2018, the Vogtle Owners further amended the joint ownership agreements to clarify and provide procedures for certain provisions of the joint ownership agreements related to adverse events that require the vote of the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 to continue construction (as amended, and together with the November 2017 amendment, the Vogtle Joint Ownership Agreements). 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 in conjunction with the nineteenth VCM report, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 were required to vote to continue construction. In September 2018, the Vogtle Owners unanimously voted to continue construction of Plant Vogtle Units 3 and 4.

Amendments to the Vogtle Joint Ownership Agreements

In connection with the vote to continue construction, Georgia Power entered into (i) the Vogtle Owner Term Sheet with the other Vogtle Owners and MEAG's wholly-owned subsidiaries MEAG SPVJ, MEAG Power SPVM, LLC (MEAG SPVM), and MEAG Power SPVP, LLC (MEAG SPVP) to take certain actions which partially mitigate potential financial exposure for the other Vogtle Owners, including additional amendments to the Vogtle Joint Ownership Agreements and the purchase of PTCs from the other Vogtle Owners at pre-established prices, and (ii) the MEAG Term Sheet with MEAG and MEAG SPVJ to provide funding with respect to MEAG SPVJ's ownership interest in Plant Vogtle Units 3 and 4 under certain circumstances. On January 14, 2019, Georgia Power, MEAG, and MEAG SPVJ entered into an agreement to implement the provisions of the MEAG Term Sheet. On February 18, 2019, Georgia Power, the other Vogtle Owners, and MEAG's wholly-owned subsidiaries MEAG SPVJ, MEAG SPVM, and MEAG SPVP entered into certain amendments to the Vogtle Joint Ownership Agreements to implement the provisions of the Vogtle Owner Term Sheet.

The ultimate outcome of these matters 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. At June 30, 2019, Georgia Power had recovered approximately $2.0 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. In December 2018, the Georgia PSC approved Georgia Power's request to increase the NCCR tariff by $88 million annually, effective January 1, 2019.

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

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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) Georgia Power's seventeenth VCM report and modified 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 related 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 $100 million in 2018 and are estimated to have negative earnings impacts of approximately $70 million in 2019 and an aggregate of approximately $630 million from 2020 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.

In February 2018, Georgia Interfaith Power & Light, Inc. (GIPL) and Partnership for Southern Equity, Inc. (PSE) filed a petition appealing the Georgia PSC's January 11, 2018 order with the Fulton County Superior Court. In March 2018, Georgia Watch filed a similar appeal to the Fulton County Superior Court for judicial review of the Georgia PSC's decision and denial of Georgia Watch's motion for reconsideration. In December 2018, the Fulton County Superior Court granted Georgia Power's motion to dismiss the two appeals. On January 9, 2019, GIPL, PSE, and Georgia Watch filed an appeal of this decision with the Georgia Court of Appeals. Georgia Power believes the appeal has no merit; however, an adverse outcome in the appeal combined with subsequent adverse action by the Georgia PSC could have a material impact on Southern Company's results of operations, financial condition, and liquidity.

In August 2018, Georgia Power filed its nineteenth VCM report with the Georgia PSC, which requested approval of $578 million of construction capital costs incurred from January 1, 2018 through June 30, 2018. On February 19, 2019, the Georgia PSC approved the nineteenth VCM, but deferred approval of $51.6 million of expenditures related to Georgia Power's portion of an administrative claim filed in the Westinghouse bankruptcy proceedings. Through the nineteenth VCM, the Georgia PSC has approved total construction capital costs incurred through June

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30, 2018 of $5.4 billion (before $1.7 billion of payments received under the Guarantee Settlement Agreement and approximately $188 million in related Customer Refunds).

On April 30, 2019, as requested by the staff of the Georgia PSC, Georgia Power reported the results of the cost and schedule validation process to the Georgia PSC. On August 30, 2019, Georgia Power will file its twentieth VCM report concurrently with its twenty-first VCM report with the Georgia PSC, which will reflect the capital cost forecast discussed previously and request approval of $1.2 billion of construction capital costs incurred from June 30, 2018 through June 30, 2019. In addition, on June 20, 2019, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into a settlement agreement related to the administrative claim filed in the Westinghouse bankruptcy proceedings. Accordingly, in the twentieth/twenty-first VCM report, Georgia Power will also request approval of the $51.6 million of associated expenditures previously deferred by the Georgia PSC.

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

See RISK FACTORS of Southern Company in 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

At June 30, 2019, Georgia Power had borrowed $3.46 billion related to Plant Vogtle Units 3 and 4 costs as provided through the Amended and Restated Loan Guarantee Agreement and related multi-advance credit facilities among Georgia Power, the DOE, and the FFB, which provide for borrowings of up to approximately $5.130 billion, subject to the satisfaction of certain conditions. See Note 8 to the financial statements under "Long-term Debt – 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, and conditions to borrowing.

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

Other Matters

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Other Matters" of Southern Company in Item 7 for additional information.

Southern Company and its subsidiaries are involved in various other matters that could affect future earnings, including matters being litigated, as well as other regulatory matters and matters that could result in asset impairments. 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 other 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, regulatory matters, or potential asset impairments cannot be determined at this time; however, for current proceedings not specifically reported in Notes (B) and (C) 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 Notes (B) and (C) 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.

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Litigation

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 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 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. Also in 2017, the defendants filed a motion to dismiss the plaintiffs' amended complaint with prejudice, to which the plaintiffs filed an opposition. In March 2018, the court 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. In April 2018, the defendants filed a motion for reconsideration of the court's order, seeking dismissal of the remaining claims in the lawsuit. In August 2018, the court denied the motion for reconsideration and denied a motion to certify the issue for interlocutory appeal.

In February 2017, Jean Vineyard and Judy Mesirov each filed a shareholder derivative lawsuit 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 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. In April 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, 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. In May 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 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 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. In the first quarter 2019, Mississippi Power and Southern Company filed motions to dismiss, which were denied by the arbitration panel on May 10, 2019.

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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 amounts for municipal franchise fees (which fees are paid 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 2017. In June 2018, the Georgia Supreme Court affirmed the judgment of the Georgia Court of Appeals and remanded the case to the trial court for further proceedings. Following a motion by Georgia Power, on February 13, 2019, the Superior Court of Fulton County ordered the parties to submit petitions to the Georgia PSC for a declaratory ruling to address certain terms the court previously held were ambiguous as used in the Georgia PSC's orders. The order entered by the Superior Court of Fulton County also conditionally certified the proposed class. In March 2019, Georgia Power and the plaintiffs filed petitions with the Georgia PSC seeking confirmation of the proper application of the municipal franchise fee schedule pursuant to the Georgia PSC's orders. Georgia Power also filed a notice of appeal with the Georgia Court of Appeals regarding the Superior Court of Fulton County's February 2019 order. The amount of any possible losses cannot be calculated at this time because, among other factors, it is unknown whether conditional class certification will be upheld and the ultimate composition of any class and whether any losses would be subject to recovery from any municipalities.

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

Mississippi Power

In conjunction with Southern Company's sale of Gulf Power, Mississippi Power and Gulf Power have committed to seek a restructuring of their 50% undivided ownership interests in Plant Daniel such that each of them would, after the restructuring, own 100% of a generating unit. On January 15, 2019, Gulf Power provided notice to Mississippi Power that Gulf Power will retire its share of the generating capacity of Plant Daniel on January 15, 2024. Mississippi Power has the option to purchase Gulf Power's ownership interest for $1 on January 15, 2024, provided that Mississippi Power exercises the option no later than 120 days prior to that date. Mississippi Power is assessing the potential operational and economic effects of Gulf Power's notice. The ultimate outcome of these matters remains subject to completion of Mississippi Power's evaluations and applicable regulatory approvals, including by the FERC and the Mississippi PSC, and cannot be determined at this time. See Note (K) to the Condensed Financial Statements under "Southern Company" herein for information regarding the sale of Gulf Power.

Southern Company Gas

See Note 3 to the financial statements in Item 8 of the Form 10-K under "Other Matters – Southern Company Gas" for information on a natural gas storage facility consisting of two salt dome caverns in Louisiana. The future performance of this facility, as well as Southern Company Gas' two other natural gas storage facilities located in California and Texas, could be impacted by ongoing changes in the U.S. natural gas storage market. Recent sales of natural gas storage facilities have resulted in losses for the sellers and may imply an impact on future rates and/or asset values. Southern Company Gas is evaluating these recent market transactions for impacts on its plans to return one of the salt dome caverns in Louisiana back to service in 2021. Sustained diminished natural gas storage values could trigger impairment of one or all of these natural gas storage facilities, which have a combined net book value of $438 million at June 30, 2019. The ultimate outcome of these matters cannot be determined at this time, but could have a material impact on Southern Company's financial statements.

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 Notes 1, 5, and 6 to the financial statements 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

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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.

Recently Issued Accounting Standards

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, 2019. Southern Company intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit agreements to meet future capital and liquidity needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.

Net cash provided from operating activities totaled $2.5 billion for the first six months of 2019, a decrease of $0.7 billion from the corresponding period in 2018. The decrease in net cash provided from operating activities was primarily due to the timing of vendor payments and the impacts of the Gulf Power disposition and the Southern Company Gas Dispositions. Net cash provided from investing activities totaled $1.0 billion for the first six months of 2019 primarily due to proceeds from the sale of Gulf Power, partially offset by 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 used for financing activities totaled $3.6 billion for the first six months of 2019 primarily due to repayments of short-term bank debt, net redemptions and repurchases of long-term debt, and common stock dividend payments. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities. See Notes (F) and (K) to the Condensed Financial Statements herein for additional information.

Significant balance sheet changes for the first six months of 2019 include:

•	decreases in assets and liabilities held for sale of $5.0 billion and $3.2 billion, respectively, primarily related to the sale of Gulf Power;

•	an increase of $2.1 billion in total stockholders' equity primarily related to the gain on the sale of Gulf Power;

•	operating lease right-of-use assets, net of amortization and operating lease obligations, each totaling $1.9 billion, recorded upon the adoption of FASB ASC Topic 842, Leases;

•

an increase of $1.7 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, partially offset by Alabama Power's reclassification of $1.4 billion to regulatory assets related to the retirement of Plant Gorgas, including $0.7 billion associated with AROs;

•	decreases of $1.5 billion in notes payable and $1.1 billion in long-term debt (including amounts due within one year) related to net repayments of short-term bank debt and long-term debt, respectively; and

•	an increase of $1.2 billion in accumulated deferred income taxes primarily related to the expected utilization of tax credit carryforwards in the 2019 tax year as a result of increased taxable income from the sale of Gulf Power.

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See FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Alabama Power" herein and Notes (A), (B), (F), (G), (K), and (L) to the Condensed Financial Statements herein for additional information.

At the end of the second quarter 2019, the market price of Southern Company's common stock was $55.28 per share (based on the closing price as reported on the NYSE) and the book value was $25.73 per share, representing a market-to-book ratio of 215%, compared to $43.92, $23.91, and 184%, respectively, at the end of 2018. Southern Company's common stock dividend for the second quarter 2019 was $0.62 per share compared to $0.60 per share in the second quarter 2018.

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 $3.1 billion will be required through June 30, 2020 to fund maturities of long-term debt. See "Sources of Capital" herein for additional information.

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 15 to the financial statements under "Southern Power" in Item 8 of the Form 10-K and Note (K) to the Condensed Financial Statements under "Southern Power" herein for additional information regarding Southern Power's plant acquisitions and construction projects.

The construction program also includes Plant Vogtle Units 3 and 4, which includes components based on new technology that only recently began initial operation in the global nuclear industry at this 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, delays, increased costs, or inconsistent quality of equipment, materials, and labor; contractor or supplier delay; nonperformance under construction, operating, or other agreements; operational readiness, including specialized operator training and required site safety programs; engineering or design problems; design and other licensing-based compliance matters, including the timely submittal by Southern Nuclear of the ITAAC documentation for each unit and the related reviews and approvals by the NRC necessary to support NRC authorization to load fuel; challenges with start-up activities, including major equipment failure, system integration, or regional transmission upgrades; and/or operational performance. See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Georgia Power – 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. 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 2019, as well as in subsequent years, will be contingent on Southern

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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, as well as funds resulting from its pending asset sale. 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. Also see Note (K) to the Condensed Financial Statements under "Southern Power" herein for additional information regarding the pending sale of Plant Mankato.

In addition, in 2014, Georgia Power entered into a loan guarantee agreement with the DOE and, in March 2019, entered into the Amended and Restated Loan Guarantee Agreement, 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 Amended and Restated Loan Guarantee Agreement, the DOE has agreed to guarantee the obligations of Georgia Power under note purchase agreements among the DOE, Georgia Power, and the FFB and related promissory notes which provide for two multi-advance term loan facilities, under which Georgia Power may make term loan borrowings through the FFB in an amount up to approximately $5.130 billion, provided that certain conditions are met. At June 30, 2019, Georgia Power had borrowed $3.46 billion under the FFB Credit Facilities. See Notes (B) and (F) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" and "DOE Loan Guarantee Borrowings," respectively, herein for additional information.

Southern Company'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. As of June 30, 2019, Southern Company's current liabilities exceeded current assets by $2.6 billion, primarily due to long-term debt that is due within one year and notes payable totaling $4.5 billion (including approximately $0.9 billion at the parent company, $1.5 billion at Georgia Power, $0.3 billion at Mississippi Power, $0.9 billion at Southern Power, and $0.8 billion at Southern Company Gas), partially offset by $1.4 billion of cash and cash equivalents. 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.

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Committed credit arrangements with banks at June 30, 2019 were as follows:

	Expires
Company	2019			2020			2022			2024				Total				Unused				Due within One Year
	(in millions)
Southern Company(a)	$	—		$	—		$	—		$	2,000			$	2,000			$	1,999			$	—
Alabama Power	3			500			—			800				1,303				1,303				3
Georgia Power	—			—			—			1,750				1,750				1,736				—
Mississippi Power	—			—			150			—				150				150				—
Southern Power(b)	—			—			—			600				600				561				—
Southern Company Gas(c)	—			—			—			1,750				1,750				1,745				—
Other	—			30			—			—				30				30				30
Southern Company Consolidated	$	3		$	530		$	150		$	6,900			$	7,583			$	7,524			$	33

(a)	Represents the Southern Company parent entity.

(b)	Does not include Southern Power Company's $120 million continuing letter of credit facility for standby letters of credit expiring in 2021, of which $30 million was unused at June 30, 2019. Southern Power's subsidiaries are not parties to its bank credit arrangement.

(c)

Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $1.25 billion of this arrangement. Southern Company Gas' committed credit arrangement also includes $500 million for which Nicor Gas is the borrower and which is restricted for working capital needs of Nicor Gas. Pursuant to this multi-year credit arrangement, the allocations between Southern Company Gas Capital and Nicor Gas may be adjusted.

See Note 8 to the financial statements 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 Alabama Power, Georgia Power, and SEGCO, 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, 2019, Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company Gas, Nicor Gas, and SEGCO were in compliance with all such covenants. None of the bank credit arrangements contain material adverse change clauses at the time of borrowings.

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

A portion of the unused credit with banks is allocated to provide liquidity support to the 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, Nicor Gas, and SEGCO. The amount of variable rate revenue bonds of the traditional electric operating companies outstanding requiring liquidity support as of June 30, 2019 was approximately $1.4 billion. In addition, at June 30, 2019, the traditional electric operating companies had approximately $272 million of revenue bonds outstanding that are required to be remarketed within the next 12 months.

Southern Company, Alabama Power, Georgia Power, Southern Power Company, Southern Company Gas, Nicor Gas, and SEGCO 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.

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Details of short-term borrowings were as follows:

		Short-term Debt at June 30, 2019							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		$	1,148			2.6	%		$	1,173			2.8	%		$	1,562
Short-term bank debt		250				2.9	%		127				3.0	%		250
Total		$	1,398			2.7	%		$	1,300			2.8	%

(*)	Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 2019.

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, 2019, 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.

The maximum potential collateral requirements under these contracts at June 30, 2019 were as follows:

Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB and/or Baa2	$	30
At BBB- and/or Baa3	$	433
At BB+ and/or Ba1(*)	$	1,935

(*)	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.

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 most of its regulated subsidiaries have taken 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 2 to the financial statements 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, including approvals and requests for additional or continued adjustments of capital structure related to the Tax Reform Legislation for Alabama Power, Georgia Power, Atlanta Gas Light, and Nicor Gas, which are expected to help mitigate the potential adverse impacts to certain of their credit metrics.

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Financing Activities

During the first six months of 2019, Southern Company issued approximately 11.5 million shares of common stock primarily through employee equity compensation plans and received proceeds of approximately $452 million.

The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first six months of 2019:

Company	Senior Note Maturities, Redemptions, and Repurchases				Revenue Bond Issuances and Reofferings of Purchased Bonds				Revenue Bond Maturities, Redemptions, and Repurchases				Other Long-Term Debt Issuances				Other Long-Term Debt Redemptions and Maturities(a)
	(in millions)
Southern Company(b)	$	2,100			$	—			$	—			$	—			$	—
Alabama Power	200				—				—				—				—
Georgia Power	—				513				223				835				3
Mississippi Power	—				43				—				—				—
Other	—				—				25				—				9
Southern Company Consolidated	$	2,300			$	556			$	248			$	835			$	12

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

(b)	Represents the Southern Company parent entity.

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. The subsidiaries also used the proceeds for their construction programs.

In January 2019, Southern Company repaid a $250 million short-term uncommitted bank credit arrangement and a $1.5 billion short-term floating rate bank loan.

Also in January 2019, through cash tender offers, Southern Company repurchased and retired approximately $522 million of the $1.0 billion aggregate principal amount outstanding of its 1.85% Senior Notes due July 1, 2019 (1.85% Notes), approximately $180 million of the $350 million aggregate principal amount outstanding of its Series 2014B 2.15% Senior Notes due September 1, 2019 (Series 2014B Notes), and approximately $504 million of the $750 million aggregate principal amount outstanding of its Series 2018A Floating Rate Notes due February 14, 2020 (Series 2018A Notes), for an aggregate purchase price, excluding accrued and unpaid interest, of approximately $1.2 billion. In addition, following the completion of the cash tender offers, in February 2019, Southern Company completed the redemption of all of the Series 2018A Notes, 1.85% Notes, and Series 2014B Notes remaining outstanding.

As reflected in the table above, in March 2019, Georgia Power made additional borrowings under the FFB Credit Facilities in an aggregate principal amount of $835 million at an interest rate of 3.213% through the final maturity date of February 20, 2044. The proceeds were used to reimburse Georgia Power for Eligible Project Costs relating to the construction of Plant Vogtle Units 3 and 4.

In June 2019, Georgia Power entered into two short-term floating rate bank loans in aggregate principal amounts of $125 million each, both of which bear interest based on one-month LIBOR.

In May 2019, Southern Power repaid at maturity a $100 million aggregate principal amount short-term bank loan.

Subsequent to June 30, 2019, Nicor Gas repaid at maturity $50 million aggregate principal amount of 4.7% first mortgage bonds due July 30, 2019.

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

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PART I

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

During the six months ended June 30, 2019, there were no material changes to Southern Company's, Alabama Power's, Georgia 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 under "Financial Instruments" and Notes 13 and 14 to the financial statements in Item 8 of the Form 10-K. Also see Notes (I) and (J) 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, 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, 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 2019 that have materially affected or are reasonably likely to materially affect Southern Company's, Alabama Power's, Georgia Power's, Mississippi Power's, Southern Power's, or Southern Company Gas' internal control over financial reporting.

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ALABAMA POWER COMPANY

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ALABAMA POWER COMPANY

CONDENSED STATEMENTS OF INCOME (UNAUDITED)

 

	For the Three Months Ended June 30,								For the Six Months Ended June 30,
	2019				2018				2019				2018
	(in millions)								(in millions)
Operating Revenues:
Retail revenues	$	1,378			$	1,338			$	2,592			$	2,624
Wholesale revenues, non-affiliates	62				65				123				139
Wholesale revenues, affiliates	4				31				63				82
Other revenues	69				69				143				131
Total operating revenues	1,513				1,503				2,921				2,976
Operating Expenses:
Fuel	252				347				553				672
Purchased power, non-affiliates	47				48				84				113
Purchased power, affiliates	69				43				90				80
Other operations and maintenance	402				402				812				788
Depreciation and amortization	200				189				399				379
Taxes other than income taxes	98				94				200				192
Total operating expenses	1,068				1,123				2,138				2,224
Operating Income	445				380				783				752
Other Income and (Expense):
Allowance for equity funds used during construction	14				14				28				27
Interest expense, net of amounts capitalized	(82		)		(80		)		(165		)		(158		)
Other income (expense), net	11				12				25				15
Total other income and (expense)	(57		)		(54		)		(112		)		(116		)
Earnings Before Income Taxes	388				326				671				636
Income taxes	89				64				151				145
Net Income	299				262				520				491
Dividends on Preferred Stock	3				3				7				7
Net Income After Dividends on Preferred Stock	$	296			$	259			$	513			$	484

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

 

	For the Three Months Ended June 30,								For the Six Months Ended June 30,
	2019				2018				2019				2018
	(in millions)								(in millions)
Net Income	$	299			$	262			$	520			$	491
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	$	300			$	263			$	522			$	493

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

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ALABAMA POWER COMPANY

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)

 

	For the Six Months Ended June 30,
	2019				2018
	(in millions)
Operating Activities:
Net income	$	520			$	491
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	493				452
Deferred income taxes	138				48
Allowance for equity funds used during construction	(28		)		(27		)
Pension, postretirement, and other employee benefits	(13		)		(28		)
Settlement of asset retirement obligations	(43		)		(19		)
Other, net	(1		)		(21		)
Changes in certain current assets and liabilities —
-Receivables	6				(153		)
-Prepayments	(59		)		(57		)
-Materials and supplies	5				(47		)
-Other current assets	(10		)		29
-Accounts payable	(246		)		(196		)
-Accrued taxes	8				134
-Accrued compensation	(88		)		(70		)
-Other current liabilities	13				116
Net cash provided from operating activities	695				652
Investing Activities:
Property additions	(833		)		(997		)
Nuclear decommissioning trust fund purchases	(139		)		(131		)
Nuclear decommissioning trust fund sales	139				131
Cost of removal, net of salvage	(48		)		(34		)
Change in construction payables	(103		)		(29		)
Other investing activities	(18		)		(15		)
Net cash used for investing activities	(1,002		)		(1,075		)
Financing Activities:
Proceeds —
Senior notes	—				500
Capital contributions from parent company	1,254				488
Redemptions — Senior notes	(200		)		—
Payment of common stock dividends	(422		)		(402		)
Other financing activities	(15		)		(21		)
Net cash provided from financing activities	617				565
Net Change in Cash, Cash Equivalents, and Restricted Cash	310				142
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	313				544
Cash, Cash Equivalents, and Restricted Cash at End of Period	$	623			$	686
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $10 and $10 capitalized for 2019 and 2018, respectively)	$	154			$	143
Income taxes, net	63				17
Noncash transactions — Accrued property additions at end of period	168				216

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

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ALABAMA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

 

Assets		At June 30, 2019				At December 31, 2018
		(in millions)
Current Assets:
Cash and cash equivalents		$	623			$	313
Receivables —
Customer accounts receivable		432				403
Unbilled revenues		173				150
Affiliated		38				94
Other accounts and notes receivable		55				51
Accumulated provision for uncollectible accounts		(10		)		(10		)
Fossil fuel stock		143				141
Materials and supplies		530				546
Prepaid expenses		170				66
Other regulatory assets		204				137
Other current assets		26				18
Total current assets		2,384				1,909
Property, Plant, and Equipment:
In service		29,070				30,402
Less: Accumulated provision for depreciation		9,397				9,988
Plant in service, net of depreciation		19,673				20,414
Nuclear fuel, at amortized cost		322				324
Construction work in progress		1,097				1,113
Total property, plant, and equipment		21,092				21,851
Other Property and Investments:
Equity investments in unconsolidated subsidiaries		64				65
Nuclear decommissioning trusts, at fair value		964				847
Miscellaneous property and investments		129				127
Total other property and investments		1,157				1,039
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization		152				—
Deferred charges related to income taxes		240				240
Deferred under recovered regulatory clause revenues		25				116
Regulatory assets – asset retirement obligations		1,016				147
Other regulatory assets, deferred		1,824				1,240
Other deferred charges and assets		177				188
Total deferred charges and other assets		3,434				1,931
Total Assets		$	28,067			$	26,730

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

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ALABAMA POWER COMPANY

CONDENSED BALANCE SHEETS (UNAUDITED)

 

Liabilities and Stockholder's Equity		At June 30, 2019				At December 31, 2018
		(in millions)
Current Liabilities:
Securities due within one year		$	1			$	201
Accounts payable —
Affiliated		321				364
Other		334				614
Customer deposits		98				96
Accrued taxes		102				44
Accrued interest		88				89
Accrued compensation		140				227
Asset retirement obligations		156				163
Other current liabilities		155				161
Total current liabilities		1,395				1,959
Long-term Debt		7,926				7,923
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		3,117				2,962
Deferred credits related to income taxes		2,006				2,027
Accumulated deferred ITCs		103				106
Employee benefit obligations		309				314
Operating lease obligations		137				—
Asset retirement obligations, deferred		3,389				3,047
Other cost of removal obligations		464				497
Other regulatory liabilities		69				69
Other deferred credits and liabilities		32				58
Total deferred credits and other liabilities		9,626				9,080
Total Liabilities		18,947				18,962
Redeemable Preferred Stock		291				291
Common Stockholder's Equity (See accompanying statements)		8,829				7,477
Total Liabilities and Stockholder's Equity		$	28,067			$	26,730

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

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ALABAMA POWER COMPANY

CONDENSED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY (UNAUDITED)

	Number of Common Shares Issued			Common Stock				Paid-In Capital				Retained Earnings				Accumulated Other Comprehensive Income (Loss)				Total
	(in millions)
Balance at December 31, 2017	31			$	1,222			$	2,986			$	2,647			$	(26	)		$	6,829
Net income after dividends on preferred stock	—			—				—				225				—				225
Capital contributions from parent company	—			—				488				—				—				488
Other comprehensive income (loss)	—			—				—				—				1				1
Cash dividends on common stock	—			—				—				(202		)		—				(202		)
Other	—			—				—				—				(6		)		(6		)
Balance at March 31, 2018	31			1,222				3,474				2,670				(31		)		7,335
Net income after dividends on preferred stock	—			—				—				259				—				259
Capital contributions from parent company	—			—				5				—				—				5
Other comprehensive income (loss)	—			—				—				—				1				1
Cash dividends on common stock	—			—				—				(200		)		—				(200		)
Other	—			—				1				—				—				1
Balance at June 30, 2018	31			$	1,222			$	3,480			$	2,729			$	(30	)		$	7,401
Balance at December 31, 2018	31			$	1,222			$	3,508			$	2,775			$	(28	)		$	7,477
Net income after dividends on preferred stock	—			—				—				217				—				217
Capital contributions from parent company	—			—				1,236				—				—				1,236
Other comprehensive income (loss)	—			—				—				—				1				1
Cash dividends on common stock	—			—				—				(211		)		—				(211		)
Balance at March 31, 2019	31			1,222				4,744				2,781				(27		)		8,720
Net income after dividends on preferred stock	—			—				—				296				—				296
Capital contributions from parent company	—			—				23				—				—				23
Other comprehensive income (loss)	—			—				—				—				1				1
Cash dividends on common stock	—			—				—				(211		)		—				(211		)
Balance at June 30, 2019	31			$	1,222			$	4,767			$	2,866			$	(26	)		$	8,829

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

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ALABAMA POWER COMPANY

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

SECOND QUARTER 2019 vs. SECOND QUARTER 2018

AND

YEAR-TO-DATE 2019 vs. YEAR-TO-DATE 2018

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, including CCR rules, reliability, fuel, capital expenditures, including improving the electric transmission and distribution systems, and restoration following major storms. Alabama Power has various regulatory mechanisms that operate to address cost recovery. Effectively operating pursuant to these regulatory mechanisms and appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Alabama Power for the foreseeable future.

Alabama Power continues to focus on several key performance indicators 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 2019 vs. Second Quarter 2018				Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)		(% change)		(change in millions)		(% change)
$37		14.3		$29		6.0

Alabama Power's net income after dividends on preferred stock for the second quarter 2019 was $296 million compared to $259 million for the corresponding period in 2018. The increase was primarily related to an increase in retail revenues associated with the impacts of customer bill credits issued in 2018 related to the Tax Reform Legislation, as well as additional capital investments recovered through Rate CNP Compliance, partially offset by a decrease in retail revenues associated with customer usage.

Alabama Power's net income after dividends on preferred stock for year-to-date 2019 was $513 million compared to $484 million for the corresponding period in 2018. This increase was primarily related to an increase in retail revenues associated with the impacts of customer bill credits issued in 2018 related to the Tax Reform Legislation, as well as additional capital investments recovered through Rate CNP Compliance. This increase was partially offset by decreases in retail revenues associated with milder weather and lower customer usage as well as increases to operations and maintenance expenses and depreciation.

See Note 2 to the financial statements under "Alabama Power – Rate RSE" in Item 8 of the Form 10-K for additional information.

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Retail Revenues

Second Quarter 2019 vs. Second Quarter 2018				Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)		(% change)		(change in millions)		(% change)
$40		3.0		$(32)		(1.2)

In the second quarter 2019, retail revenues were $1.38 billion compared to $1.34 billion for the corresponding period in 2018. For year-to-date 2019, retail revenues were $2.59 billion compared to $2.62 billion for the corresponding period in 2018.

Details of the changes in retail revenues were as follows:

	Second Quarter 2019							Year-to-Date 2019
	(in millions)				(% change)			(in millions)				(% change)
Retail – prior year	$	1,338						$	2,624
Estimated change resulting from –
Rates and pricing	62				4.7	%		96				3.7	%
Sales decline	(15		)		(1.1	)		(31		)		(1.2	)
Weather	6				0.4			(19		)		(0.7	)
Fuel and other cost recovery	(13		)		(1.0	)		(78		)		(3.0	)
Retail – current year	$	1,378			3.0	%		$	2,592			(1.2	)%

Revenues associated with changes in rates and pricing increased in the second quarter and year-to-date 2019 when compared to the corresponding periods in 2018 primarily due to the impacts of customer bill credits related to the Tax Reform Legislation in 2018, as well as additional capital investments recovered through Rate CNP Compliance. See Note 2 to the financial statements under "Alabama Power – Rate RSE" and " – Rate CNP Compliance" 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 2019 when compared to the corresponding periods in 2018. Weather-adjusted residential KWH sales decreased 1.5% and 2.0% in the second quarter and year-to-date 2019, respectively, and weather-adjusted commercial KWH sales decreased 1.2% and 2.3% in the second quarter and year-to-date 2019, respectively, when compared to the corresponding periods in 2018. These decreases primarily resulted from customer initiatives in energy savings for commercial customers and more energy-efficient residential appliances. Industrial KWH sales decreased 3.2% and 3.1% in the second quarter and year-to-date 2019, respectively, when compared to the corresponding periods in 2018 as a result of a decrease in demand resulting from changes in production levels primarily in the primary metals and chemicals sectors for the second quarter 2019 and primary metals, chemicals, and paper sectors for year-to-date 2019.

Residential and commercial sales revenues decreased year-to-date 2019 by 1.2% and 0.7%, respectively, due to milder weather in the first quarter 2019 when compared to the corresponding period in 2018.

Fuel and other cost recovery revenues decreased in the second quarter and year-to-date 2019 when compared to the corresponding periods in 2018 primarily due to a decrease in 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 2 to the financial statements under "Alabama Power" in Item 8 of the Form 10-K for additional information.

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Wholesale Revenues – Non-Affiliates

Second Quarter 2019 vs. Second Quarter 2018				Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)		(% change)		(change in millions)		(% change)
$(3)		(4.6)		$(16)		(11.5)

Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Alabama Power's and the Southern Company system's generation, demand for energy within the Southern Company system's service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not affect net income. Short-term opportunity energy sales are also included in wholesale energy sales to non-affiliates. These opportunity sales are made at market-based rates that generally provide a margin above Alabama Power's variable cost to produce the energy.

For year-to-date 2019, wholesale revenues from sales to non-affiliates were $123 million compared to $139 million for the corresponding period in 2018. The decrease was primarily due to a 7.1% decrease in KWH sales as a result of lower demand and a 4.8% decrease in the price of energy due to lower natural gas prices in 2019 compared to the corresponding period in 2018.

Wholesale Revenues – Affiliates

Second Quarter 2019 vs. Second Quarter 2018				Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)		(% change)		(change in millions)		(% change)
$(27)		(87.1)		$(19)		(23.2)

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.

In the second quarter 2019, wholesale revenues from sales to affiliates were $4 million compared to $31 million for the corresponding period in 2018. The decrease was primarily due to an 87.4% decrease in KWH sales as a result of decreased coal generation associated with the retirement of Plant Gorgas Units 8, 9, and 10 and a 6.7% decrease in the price of energy as a result of lower natural gas prices in the second quarter 2019 compared to the corresponding period in 2018.

For year-to-date 2019, wholesale revenues from sales to affiliates were $63 million compared to $82 million for the corresponding period in 2018. The decrease was primarily due to a 13.1% decrease in KWH sales as a result of decreased coal generation associated with the retirement of Plant Gorgas Units 8, 9, and 10 and an 11.0% decrease in the price of energy due to increased hydro generation in 2019 as compared to the corresponding period in 2018.

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Fuel and Purchased Power Expenses

	Second Quarter 2019 vs. Second Quarter 2018						Year-to-Date 2019 vs. Year-to-Date 2018
	(change in millions)				(% change)		(change in millions)				(% change)
Fuel	$	(95	)		(27.4)		$	(119	)		(17.7	)
Purchased power – non-affiliates	(1		)		(2.1)		(29		)		(25.7	)
Purchased power – affiliates	26				60.5		10				12.5
Total fuel and purchased power expenses	$	(70	)				$	(138	)

In the second quarter 2019, fuel and purchased power expenses were $368 million compared to $438 million for the corresponding period in 2018. For year-to-date 2019, fuel and purchased power expenses were $727 million compared to $865 million for the corresponding period in 2018. These decreases were primarily related to the volume of KWHs generated (excluding hydro) and purchased.

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 2 to the financial statements under "Alabama Power – 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 2019		Second Quarter 2018		Year-to-Date 2019		Year-to-Date 2018
Total generation (in billions of KWHs)	12		15		29		31
Total purchased power (in billions of KWHs)	3		2		4		3
Sources of generation (percent) —
Coal	43		53		43		52
Nuclear	26		20		24		21
Gas	23		20		21		19
Hydro	8		7		12		8
Cost of fuel, generated (in cents per net KWH) — (a)
Coal	2.86		2.79		2.82		2.74
Nuclear	0.78		0.80		0.78		0.77
Gas	2.48		2.51		2.53		2.69
Average cost of fuel, generated (in cents per net KWH)(a)(b)	2.18		2.31		2.19		2.27
Average cost of purchased power (in cents per net KWH)(c)	4.01		4.72		4.45		5.72

(a)	In the second quarter and year-to-date 2018, cost of fuel and average cost of fuel, generated exclude a $30 million adjustment in accordance with an Alabama PSC accounting order. See Note 2 to the financial statements under "Alabama Power – Tax Reform Accounting Order" in Item 8 of the Form 10-K for additional information.

(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 2019, fuel expense was $252 million compared to $347 million for the corresponding period in 2018. The decrease was primarily due to a 31.3% decrease in the volume of KWHs generated by coal and an 11.9% increase in the volume of KWHs generated by nuclear.

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For year-to-date 2019, fuel expense was $553 million compared to $672 million for the corresponding period in 2018. The decrease was primarily due to a 45.3% increase in the volume of KWHs generated by hydro, a 21.9% decrease in the volume of KWHs generated by coal, a 5.1% increase in the volume of KWHs generated by nuclear, and a 6.0% decrease in the average cost of natural gas per KWH generated, which excludes fuel associated with tolling agreements.

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 (Tax Reform Accounting Order). See Note 2 to the financial statements under "Alabama Power – Tax Reform Accounting Order" in Item 8 of the Form 10-K for additional information.

Purchased Power – Non-Affiliates

For year-to-date 2019, purchased power expense from non-affiliates was $84 million compared to $113 million for the corresponding period in 2018. The decrease was primarily related to a 14.3% decrease in the average cost of purchased power per KWH due to lower natural gas prices and an 11.9% decrease in the amount of energy purchased due to milder weather in the first quarter 2019 compared to the corresponding period in 2018.

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 2019, purchased power expense from affiliates was $69 million compared to $43 million for the corresponding period in 2018. For year-to-date 2019, purchased power expense from affiliates was $90 million compared to $80 million for the corresponding period in 2018. These increases were primarily related to the availability of lower-cost generation compared to Alabama Power's owned generation and a decrease in coal generation as a result of the retirement of Plant Gorgas Units 8, 9, and 10.

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 2019 vs. Second Quarter 2018				Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)		(% change)		(change in millions)		(% change)
$—		—		$24		3.0

For year-to-date 2019, other operations and maintenance expenses were $812 million compared to $788 million for the corresponding period in 2018. This increase was primarily due to increases of $15 million in Rate CNP Compliance-related expenses and $13 million in steam generation costs primarily due to the timing of outages.

Depreciation and Amortization

Second Quarter 2019 vs. Second Quarter 2018				Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)		(% change)		(change in millions)		(% change)
$11		5.8		$20		5.3

In the second quarter 2019, depreciation and amortization was $200 million compared to $189 million for the corresponding period in 2018. For year-to-date 2019, depreciation and amortization was $399 million compared to $379 million for the corresponding period in 2018. These increases were primarily due to additional plant in service associated with steam, distribution, and transmission.

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Other Income (Expense), Net

Second Quarter 2019 vs. Second Quarter 2018				Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)		(% change)		(change in millions)		(% change)
$(1)		(8.3)		$10		66.7

For year-to-date 2019, other income (expense), net was $25 million compared to $15 million for the corresponding period in 2018. This increase was primarily due to increases in interest income from temporary cash investments and non-service cost-related pension income.

Income Taxes

Second Quarter 2019 vs. Second Quarter 2018				Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)		(% change)		(change in millions)		(% change)
$25		39.1		$6		4.1

In the second quarter 2019, income taxes were $89 million compared to $64 million for the corresponding period in 2018. This increase was primarily due to higher pre-tax earnings in the second quarter 2019 compared to the corresponding period in 2018 and the application of the Tax Reform Accounting Order in 2018. See Note 2 to the financial statements under "Alabama Power – Tax Reform Accounting Order" in Item 8 of the Form 10-K for additional information.

FUTURE EARNINGS POTENTIAL

The results of operations discussed above are not necessarily indicative of Alabama Power's future earnings potential. The level of Alabama Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Alabama Power's primary business of 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 the weak pace of growth in new customers and electricity use per customer, especially in residential and commercial markets. 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 GHG strategies to assess upcoming requirements and compliance costs associated with these environmental laws and regulations and to achieve stated goals. Related costs may result from the installation of additional environmental controls, closure and monitoring of CCR facilities, unit retirements, or changing fuel sources for certain existing units, as well as related upgrades to Alabama Power's transmission and distribution systems, and may impact future electric generating unit retirement and replacement decisions, results of operations, cash flows, and/or financial condition. These costs are being collected through existing ratemaking and billing provisions. The ultimate impact of environmental laws and regulations and GHG

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goals will depend on various factors, such as state adoption and implementation of requirements, the availability and cost of any deployed technology, fuel prices, 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 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/or 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 of the Form 10-K and Note 2 to the financial statements under "Alabama Power – Rate CNP Compliance" and Note 3 to the financial statements under "Environmental Remediation" in Item 8 of the Form 10-K for additional information.

Environmental Laws and Regulations

Coal Combustion Residuals

In June 2019, Alabama Power recorded an increase of approximately $308 million to its AROs primarily related to the CCR Rule and the related state rule based on management's completion of closure designs during the second quarter 2019 for all but two of its ash pond facilities. The additional estimated costs to close these ash ponds under the planned closure-in-place methodology primarily relate to cost inputs from contractor bids, internal drainage and dewatering system designs, and increases in the estimated ash volumes. The cost estimate for the remaining ash pond facilities will be updated within the next 12 months and the change could be material.

As further analysis is performed and additional details are developed with respect to all ash pond closures, Alabama Power expects to periodically update these cost estimates as necessary. Additionally, the closure designs and plans are subject to approval by environmental regulatory agencies. 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 this matter cannot be determined at this time. See Note 6 to the financial statements in Item 8 of the Form 10-K and Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information.

Global Climate Issues

On July 8, 2019, the EPA published the final Affordable Clean Energy rule (ACE Rule) to repeal and replace the CPP. Implementation of the CPP has been stayed by the U.S. Supreme Court since 2016. The ACE Rule requires states to develop unit-specific CO₂ emission rate standards for existing coal-fired units based on heat-rate efficiency improvements. Combustion turbines, including natural gas combined cycles, are not included as affected sources in the ACE Rule. Alabama Power has ownership interests in seven coal-fired units to which the ACE Rule is applicable. The ultimate impact of the ACE Rule, including the repeal and replacement of the CPP, to Alabama Power will depend on state implementation plan requirements and the outcome of any associated legal challenges and cannot be determined at this time.

FERC Matters

See Note 2 to the financial statements under "FERC Matters – Open Access Transmission Tariff" in Item 8 of the Form 10-K for additional information.

On June 28, 2019, the FERC approved a settlement agreement between Alabama Municipal Electric Authority and Cooperative Energy and SCS and the traditional electric operating companies (including Alabama Power) agreeing to an OATT rate reduction based on a 10.6% ROE, with a retroactive effective date of May 10, 2018, and a five-year moratorium on these parties seeking changes to the OATT formula rate. The terms of the OATT settlement agreement will not have a material impact on the financial statements of Alabama Power.

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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 Note 2 to the financial statements under "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.

Environmental Accounting Order

On April 15, 2019, Alabama Power retired Plant Gorgas Units 8, 9, and 10 and reclassified approximately $654 million of the unrecovered asset balances to regulatory assets, which are being recovered over the units' remaining useful lives, the latest being through 2037, as established prior to the decision to retire. Additionally, approximately $700 million of net capitalized asset retirement costs were reclassified to a regulatory asset in accordance with accounting guidance provided by the Alabama PSC. The asset retirement costs are being recovered through 2055. See Note 2 to the financial statements under "Alabama Power – Environmental Accounting Order" and Note 6 in Item 8 of the Form 10-K for additional information.

Other Matters

Alabama Power is involved in various other matters that could affect future earnings, including matters being litigated and regulatory matters. 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 other 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 determined at this time; however, for current proceedings not specifically reported in Notes (B) and (C) 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 Notes (B) and (C) 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.

In response to changing customer expectations, payment patterns, and ongoing efforts to increase overall operating efficiencies, Alabama Power initiated a plan to close 40 of its 86 payment offices by the end of 2019. Charges associated with these activities are not expected to have a material impact on Alabama Power's financial statements.

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 Notes 1, 5, and 6 to the financial statements 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.

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Recently Issued Accounting Standards

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, 2019. 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 $695 million for the first six months of 2019, an increase of $43 million as compared to the first six months of 2018. The increase in net cash provided from operating activities was primarily due to increased fuel cost recovery, partially offset by the prior year impacts of customer billing reductions related to the Tax Reform Legislation. Net cash used for investing activities totaled $1.0 billion for the first six months of 2019 primarily related to additional capital expenditures for distribution, environmental, and transmission assets. Net cash provided from financing activities totaled $617 million for the first six months of 2019 primarily due to capital contributions from Southern Company, partially offset by a payment of common stock dividends and a long-term debt maturity. 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 2019 include increases of $869 million in regulatory assets associated with AROs and $584 million in other regulatory assets, deferred and a decrease of $759 million in property, plant, and equipment. These changes were primarily due to the impacts of retiring and reclassifying Plant Gorgas Units 8, 9, and 10. See Note 2 to the financial statements in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein under "Alabama Power – Environmental Accounting Order" for additional information. Other significant increases include $1.4 billion in total common stockholder's equity, primarily due to a $1.2 billion capital contribution from Southern Company, $342 million in asset retirement obligations, deferred due to an increase in the ARO estimate primarily related to ash pond facilities, and $310 million in cash and cash equivalents. See Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" 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 Alabama Power in Item 7 of the Form 10-K for a description of Alabama Power's capital requirements and contractual obligations. There are no scheduled maturities of long-term debt through June 30, 2020.

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.

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

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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. In January 2019, Alabama Power received a capital contribution totaling $1.225 billion from Southern Company. 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, 2019, Alabama Power had approximately $623 million of cash and cash equivalents. Committed credit arrangements with banks at June 30, 2019 were as follows:

Expires
2019				2020				2024				Total				Unused
(in millions)
$	3			$	500			$	800			$	1,303			$	1,303

See Note 8 to the financial statements 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.

As reflected in the table above, in May 2019, Alabama Power amended its $800 million multi-year credit arrangement, which, among other things, extended the maturity date from 2022 to 2024.

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, 2019, 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, 2019. At June 30, 2019, Alabama Power had $87 million of fixed rate pollution control revenue bonds outstanding that were required to be reoffered within the next 12 months.

Alabama Power also has substantial cash flow from operating activities and access to the 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.

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Details of short-term borrowings were as follows:

	Short-term Debt During the Period(*)
	Average Amount Outstanding				Weighted Average Interest Rate			Maximum Amount Outstanding
	(in millions)							(in millions)
Commercial paper	$	26			2.6	%		$	190

(*)	Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 2019. No short-term debt was outstanding at June 30, 2019.

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, 2019, 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. At June 30, 2019, the maximum potential collateral requirements at a rating below BBB- and/or Baa3 totaled approximately $359 million.

Included in these amounts are certain agreements that could require collateral in the event that either Alabama Power or Georgia Power (an affiliate 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 2 to the financial statements under "Alabama Power – Rate RSE" in Item 8 of the Form 10-K for additional information.

Financing Activities

In February 2019, Alabama Power repaid at maturity $200 million aggregate principal amount of Series Z 5.125% Senior Notes due February 15, 2019.

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.

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CONDENSED STATEMENTS OF INCOME (UNAUDITED)

	For the Three Months Ended June 30,								For the Six Months Ended June 30,
	2019				2018				2019				2018
	(in millions)								(in millions)
Operating Revenues:
Retail revenues	$	1,946			$	1,889			$	3,614			$	3,688
Wholesale revenues, non-affiliates	33				36				62				80
Wholesale revenues, affiliates	3				3				5				13
Other revenues	135				120				270				227
Total operating revenues	2,117				2,048				3,951				4,008
Operating Expenses:
Fuel	390				378				689				790
Purchased power, non-affiliates	124				111				242				233
Purchased power, affiliates	134				178				310				349
Other operations and maintenance	463				457				913				863
Depreciation and amortization	244				230				483				458
Taxes other than income taxes	115				106				220				214
Estimated loss on Plant Vogtle Units 3 and 4	—				1,060				—				1,060
Total operating expenses	1,470				2,520				2,857				3,967
Operating Income (Loss)	647				(472		)		1,094				41
Other Income and (Expense):
Interest expense, net of amounts capitalized	(105		)		(102		)		(201		)		(208		)
Other income (expense), net	35				35				77				73
Total other income and (expense)	(70		)		(67		)		(124		)		(135		)
Earnings (Loss) Before Income Taxes	577				(539		)		970				(94		)
Income taxes (benefit)	129				(143		)		211				(50		)
Net Income (Loss)	$	448			$	(396	)		$	759			$	(44	)

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended June 30,								For the Six Months Ended June 30,
	2019				2018				2019				2018
	(in millions)								(in millions)
Net Income (Loss)	$	448			$	(396	)		$	759			$	(44	)
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(9), $-, $(9), and $-, respectively	(28		)		—				(28		)		—
Reclassification adjustment for amounts included in net income, net of tax of $-, $-, $-, and $1, respectively	1				1				1				2
Total other comprehensive income (loss)	(27		)		1				(27		)		2
Comprehensive Income (Loss)	$	421			$	(395	)		$	732			$	(42	)

The accompanying notes as they relate to Georgia 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,
	2019				2018
	(in millions)
Operating Activities:
Net income (loss)	$	759			$	(44	)
Adjustments to reconcile net income (loss) to net cash provided from operating activities —
Depreciation and amortization, total	583				562
Deferred income taxes	153				(256		)
Pension, postretirement, and other employee benefits	(56		)		(47		)
Settlement of asset retirement obligations	(76		)		(49		)
Estimated loss on Plant Vogtle Units 3 and 4	—				1,060
Other, net	—				29
Changes in certain current assets and liabilities —
-Receivables	(43		)		(103		)
-Fossil fuel stock	(26		)		38
-Prepaid income taxes	63				115
-Other current assets	22				25
-Accounts payable	(94		)		(87		)
-Accrued taxes	(139		)		(89		)
-Accrued compensation	(32		)		(56		)
-Other current liabilities	(2		)		(26		)
Net cash provided from operating activities	1,112				1,072
Investing Activities:
Property additions	(1,712		)		(1,501		)
Nuclear decommissioning trust fund purchases	(266		)		(440		)
Nuclear decommissioning trust fund sales	260				435
Cost of removal, net of salvage	(107		)		(50		)
Change in construction payables, net of joint owner portion	(5		)		86
Payments pursuant to LTSAs	(9		)		(46		)
Proceeds from dispositions and asset sales	9				134
Other investing activities	(4		)		(11		)
Net cash used for investing activities	(1,834		)		(1,393		)
Financing Activities:
Increase in notes payable, net	11				480
Proceeds —
FFB loan	835				—
Pollution control revenue bonds	513				—
Short-term borrowings	250				—
Capital contributions from parent company	46				1,502
Redemptions and repurchases —
Senior notes	—				(1,000		)
Pollution control revenue bonds	(223		)		(398		)
Short-term borrowings	—				(150		)
Other long-term debt	—				(100		)
Payment of common stock dividends	(788		)		(691		)
Premiums on redemption and repurchases of senior notes	—				(152		)
Other financing activities	(24		)		(11		)
Net cash provided from (used for) financing activities	620				(520		)
Net Change in Cash, Cash Equivalents, and Restricted Cash	(102		)		(841		)
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	112				852
Cash, Cash Equivalents, and Restricted Cash at End of Period	$	10			$	11
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $16 and $12 capitalized for 2019 and 2018, respectively)	$	179			$	211
Income taxes, net	(6		)		64
Noncash transactions — Accrued property additions at end of period	650				669

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

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CONDENSED BALANCE SHEETS (UNAUDITED)

 

Assets		At June 30, 2019				At December 31, 2018
		(in millions)
Current Assets:
Cash and cash equivalents		$	10			$	4
Restricted cash and cash equivalents		—				108
Receivables —
Customer accounts receivable		603				591
Unbilled revenues		267				208
Under recovered fuel clause revenues		69				115
Joint owner accounts receivable		178				170
Affiliated		16				39
Other accounts and notes receivable		240				80
Accumulated provision for uncollectible accounts		(2		)		(2		)
Fossil fuel stock		257				231
Materials and supplies		513				519
Prepaid expenses		68				142
Other regulatory assets		240				199
Other current assets		58				70
Total current assets		2,517				2,474
Property, Plant, and Equipment:
In service		38,517				37,675
Less: Accumulated provision for depreciation		12,140				12,096
Plant in service, net of depreciation		26,377				25,579
Nuclear fuel, at amortized cost		549				550
Construction work in progress		5,193				4,833
Total property, plant, and equipment		32,119				30,962
Other Property and Investments:
Equity investments in unconsolidated subsidiaries		51				51
Nuclear decommissioning trusts, at fair value		978				873
Miscellaneous property and investments		74				72
Total other property and investments		1,103				996
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization		1,492				—
Deferred charges related to income taxes		518				517
Regulatory assets – asset retirement obligations		2,839				2,644
Other regulatory assets, deferred		2,272				2,258
Other deferred charges and assets		379				514
Total deferred charges and other assets		7,500				5,933
Total Assets		$	43,239			$	40,365

The accompanying notes as they relate to Georgia 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, 2019				At December 31, 2018
		(in millions)
Current Liabilities:
Securities due within one year		$	988			$	617
Notes payable		555				294
Accounts payable —
Affiliated		477				575
Other		901				890
Customer deposits		282				276
Accrued taxes		238				377
Accrued interest		112				105
Accrued compensation		163				221
Asset retirement obligations		240				202
Other regulatory liabilities		145				169
Other current liabilities		383				183
Total current liabilities		4,484				3,909
Long-term Debt		10,150				9,364
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		3,212				3,062
Deferred credits related to income taxes		3,078				3,080
Accumulated deferred ITCs		257				262
Employee benefit obligations		550				599
Operating lease obligations		1,377				—
Asset retirement obligations, deferred		5,643				5,627
Other deferred credits and liabilities		172				139
Total deferred credits and other liabilities		14,289				12,769
Total Liabilities		28,923				26,042
Common Stockholder's Equity (See accompanying statements)		14,316				14,323
Total Liabilities and Stockholder's Equity		$	43,239			$	40,365

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

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CONDENSED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY (UNAUDITED)

	Number of Common Shares Issued			Common Stock				Paid-In Capital				Retained Earnings				Accumulated Other Comprehensive Income (Loss)				Total
	(in millions)
Balance at December 31, 2017	9			$	398			$	7,328			$	4,215			$	(10	)		$	11,931
Net income	—			—				—				352				—				352
Capital contributions from parent company	—			—				1,476				—				—				1,476
Other comprehensive income (loss)	—			—				—				—				1				1
Cash dividends on common stock	—			—				—				(339		)		—				(339		)
Other	—			—				1				—				(2		)		(1		)
Balance at March 31, 2018	9			398				8,805				4,228				(11		)		13,420
Net loss	—			—				—				(396		)		—				(396		)
Capital contributions from parent company	—			—				29				—				—				29
Other comprehensive income (loss)	—			—				—				—				1				1
Cash dividends on common stock	—			—				—				(352		)		—				(352		)
Balance at June 30, 2018	9			$	398			$	8,834			$	3,480			$	(10	)		$	12,702
Balance at December 31, 2018	9			$	398			$	10,322			$	3,612			$	(9	)		$	14,323
Net income	—			—				—				311				—				311
Capital contributions from parent company	—			—				29				—				—				29
Other comprehensive income (loss)	—			—				—				—				1				1
Cash dividends on common stock	—			—				—				(394		)		—				(394		)
Other	—			—				(1		)		—				—				(1		)
Balance at March 31, 2019	9			398				10,350				3,529				(8		)		14,269
Net income	—			—				—				448				—				448
Capital contributions from parent company	—			—				20				—				—				20
Other comprehensive income (loss)	—			—				—				—				(27		)		(27		)
Cash dividends on common stock	—			—				—				(394		)		—				(394		)
Other	—			—				1				(1		)		—				—
Balance at June 30, 2019	9			$	398			$	10,371			$	3,582			$	(35	)		$	14,316

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

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

SECOND QUARTER 2019 vs. SECOND QUARTER 2018

AND

YEAR-TO-DATE 2019 vs. YEAR-TO-DATE 2018

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 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, including CCR rules, reliability, fuel, capital expenditures, including new generating facilities and expanding and improving transmission and distribution facilities, 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 June 28, 2019, Georgia Power filed a base rate case with the Georgia PSC. The filing includes a three-year Alternate Rate Plan with requested rate increases totaling $563 million, $145 million, and $234 million effective January 1, 2020, January 1, 2021, and January 1, 2022, respectively. The ultimate outcome of this matter cannot be determined at this time. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters" – "Rate Plans" herein for additional information.

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). Georgia Power holds a 45.7% ownership interest in Plant Vogtle Units 3 and 4. 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. The current expected in-service dates remain November 2021 for Unit 3 and November 2022 for Unit 4.

In the second quarter 2018, Georgia Power revised its base capital 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 approximately $188 million in related Customer Refunds), with respect to Georgia Power's ownership interest.

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 were required to vote to continue construction. In September 2018, the Vogtle Owners unanimously voted to continue construction of Plant Vogtle Units 3 and 4. In connection with the vote to continue construction, Georgia Power entered into (i) a binding term sheet (Vogtle Owner Term Sheet) with the other Vogtle Owners and certain of MEAG's wholly-owned subsidiaries, including MEAG Power SPVJ, LLC (MEAG SPVJ), to take certain actions which partially mitigate potential financial exposure for the other Vogtle Owners and (ii) a term sheet (MEAG Term Sheet) with MEAG and MEAG SPVJ to provide funding with respect to MEAG SPVJ's ownership interest in Plant Vogtle Units 3 and 4 under certain circumstances. On January 14, 2019, Georgia Power, MEAG, and MEAG SPVJ entered into an agreement to implement the provisions of the MEAG Term Sheet. On February 18, 2019, Georgia Power, the other Vogtle Owners, and certain of MEAG's wholly-owned subsidiaries

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entered into certain amendments to their joint ownership agreements to implement the provisions of the Vogtle Owner Term Sheet.

In April 2019, Southern Nuclear completed a cost and schedule validation process to verify and update quantities of commodities remaining to install, labor hours to install remaining quantities and related productivity, testing and system turnover requirements, and forecasted staffing needs and related costs. This process confirmed the total estimated project capital cost forecast for Plant Vogtle Units 3 and 4. The expected in-service dates of November 2021 for Unit 3 and November 2022 for Unit 4, as previously approved by the Georgia PSC, remain unchanged.

In March 2019, Georgia Power entered into the Amended and Restated 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, up to approximately $5.130 billion. At June 30, 2019, Georgia Power had a total of $3.46 billion of borrowings outstanding under the related multi-advance credit facilities.

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

See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Nuclear Construction" and Note (F) to the Condensed Financial Statements under "DOE Loan Guarantee Borrowings" herein for additional information.

RESULTS OF OPERATIONS

Net Income (Loss)

Second Quarter 2019 vs. Second Quarter 2018				Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)		(% change)		(change in millions)		(% change)
$844		N/M		$803		N/M

N/M - Not meaningful

Georgia Power's net income for the second quarter 2019 was $448 million compared to a net loss of $396 million for the corresponding period in 2018. The change was 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 and an increase in retail revenues associated with an increase in the NCCR tariff effective January 1, 2019 and warmer weather in the second quarter 2019 compared to the corresponding period in 2018.

For year-to-date 2019, net income was $759 million compared to a net loss of $44 million for the corresponding period in 2018. The change was 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, an increase in other revenues primarily related to unregulated new energy conservation project sales, and an increase in retail revenues associated with an increase in the NCCR tariff effective January 1, 2019. Partially offsetting the change was a decrease in retail revenues associated with milder weather in the first quarter 2019 compared to the corresponding period in 2018 and higher non-fuel operations and maintenance expenses.

Retail Revenues

Second Quarter 2019 vs. Second Quarter 2018				Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)		(% change)		(change in millions)		(% change)
$57		3.0		$(74)		(2.0)

In the second quarter 2019, retail revenues were $1.95 billion compared to $1.89 billion for the corresponding period in 2018. For year-to-date 2019, retail revenues were $3.61 billion compared to $3.69 billion for the corresponding period in 2018.

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Details of the changes in retail revenues were as follows:

	Second Quarter 2019							Year-to-Date 2019
	(in millions)				(% change)			(in millions)				(% change)
Retail – prior year	$	1,889						$	3,688
Estimated change resulting from –
Rates and pricing	52				2.8	%		61				1.7	%
Sales decline	(15		)		(0.8	)		(11		)		(0.3	)
Weather	28				1.5			(29		)		(0.8	)
Fuel cost recovery	(8		)		(0.4	)		(95		)		(2.6	)
Retail – current year	$	1,946			3.1	%		$	3,614			(2.0	)%

Revenues associated with changes in rates and pricing increased in the second quarter and year-to-date 2019 when compared to the corresponding periods in 2018. The increases were primarily due to an increase in the NCCR tariff effective January 1, 2019. The year-to-date 2019 increase also reflects the rate pricing effect of decreased customer usage, partially offset by lower contributions from commercial and industrial customers with variable demand-driven pricing. See 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 decreased in the second quarter and year-to-date 2019 when compared to the corresponding periods in 2018. Weather-adjusted residential KWH sales decreased 0.8% in the second quarter 2019 primarily due to a decline in average customer usage, partially offset by customer growth. Weather-adjusted residential KWH sales increased 0.7% for year-to-date 2019 primarily due to customer growth, partially offset by a decline in average customer usage resulting from increases in energy saving initiatives and multi-family housing. Weather-adjusted commercial KWH sales decreased 1.2% and 1.1% in the second quarter and year-to-date 2019, respectively, primarily due to a decline in average customer usage resulting from an increase in energy saving initiatives, partially offset by customer growth. Weather-adjusted industrial KWH sales decreased 0.9% and 0.7% in the second quarter and year-to-date 2019, respectively, primarily due to decreases in the stone, clay, and glass and textile sectors. Additionally, the decrease in the second quarter 2019 also reflects a decrease in the paper sector and the decrease for year-to-date 2019 was partially offset by an increase in the paper sector.

Fuel revenues and costs are allocated between retail and wholesale jurisdictions. Retail fuel cost recovery revenues decreased in the second quarter and year-to-date 2019 when compared to the corresponding periods in 2018. For year-to-date 2019, the decrease was primarily due to decreased energy sales driven by milder weather in the first quarter 2019, resulting in lower customer demand, and lower generation 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.

Wholesale Revenues – Non-Affiliates

Second Quarter 2019 vs. Second Quarter 2018				Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)		(% change)		(change in millions)		(% change)
$(3)		(8.3)		$(18)		(22.5)

Wholesale revenues from sales to non-affiliates consist of PPAs and short-term opportunity sales. Wholesale revenues from PPAs have both capacity and energy components. Wholesale capacity revenues from PPAs are recognized either on a levelized basis over the appropriate contract period or the amounts billable under the contract terms and provide for recovery of fixed costs and a return on investment. Wholesale revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Georgia Power's and the Southern Company system's generation, demand for energy within the Southern Company system's

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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. Short-term opportunity sales are made at market-based rates that generally provide a margin above Georgia Power's variable cost of energy.

In the second quarter 2019, wholesale revenues from sales to non-affiliates were $33 million compared to $36 million for the corresponding period in 2018. For year-to-date 2019, wholesale revenues from sales to non-affiliates were $62 million compared to $80 million for the corresponding period in 2018. The decrease for year-to-date 2019 was primarily due to a decrease in energy revenues primarily due to lower customer demand and lower energy prices.

Other Revenues

Second Quarter 2019 vs. Second Quarter 2018				Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)		(% change)		(change in millions)		(% change)
$15		12.5		$43		18.9

In the second quarter 2019, other revenues were $135 million compared to $120 million for the corresponding period in 2018. The increase was primarily due to revenue increases of $6 million from unregulated sales associated with new energy conservation projects, $3 million from OATT sales, and $3 million from power delivery maintenance contracts.

For year-to-date 2019, other revenues were $270 million compared to $227 million for the corresponding period in 2018. The increase was primarily due to revenue increases of $11 million from unregulated new energy conservation project sales, $9 million from OATT sales, $8 million from outdoor lighting LED conversions and sales, $4 million from solar application fees, and $3 million from power delivery maintenance contracts.

Fuel and Purchased Power Expenses

	Second Quarter 2019 vs. Second Quarter 2018							Year-to-Date 2019 vs. Year-to-Date 2018
	(change in millions)				(% change)			(change in millions)				(% change)
Fuel	$	12			3.2			$	(101	)		(12.8	)
Purchased power – non-affiliates	13				11.7			9				3.9
Purchased power – affiliates	(44		)		(24.7	)		(39		)		(11.2	)
Total fuel and purchased power expenses	$	(19	)					$	(131	)

In the second quarter 2019, total fuel and purchased power expenses were $648 million compared to $667 million in the corresponding period in 2018. The decrease was primarily due to a net decrease of $19 million related to the volume of KWHs generated and purchased.

For year-to-date 2019, total fuel and purchased power expenses were $1.24 billion compared to $1.37 billion in the corresponding period in 2018. The decrease was primarily due to a $114 million decrease related to the average cost of fuel and purchased power primarily related to lower energy prices and more rainfall for hydro generation in the first quarter 2019 and a net $17 million decrease in the volume of KWHs generated and purchased.

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.

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

	Second Quarter 2019		Second Quarter 2018		Year-to-Date 2019		Year-to-Date 2018
Total generation (in billions of KWHs)	16		15		29		31
Total purchased power (in billions of KWHs)	6		8		15		14
Sources of generation (percent) —
Gas	45		40		47		42
Coal	26		29		23		29
Nuclear	26		28		26		26
Hydro	3		3		4		3
Cost of fuel, generated (in cents per net KWH) —
Gas	2.48		2.61		2.53		2.67
Coal	3.18		3.26		3.20		3.31
Nuclear	0.81		0.83		0.81		0.83
Average cost of fuel, generated (in cents per net KWH)	2.23		2.30		2.22		2.37
Average cost of purchased power (in cents per net KWH)(*)	4.59		4.37		4.23		4.81

(*)	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 2019, fuel expense was $390 million compared to $378 million in the corresponding period in 2018. The increase was primarily due to a 9.5% increase in the volume of KWHs generated primarily due to warmer weather in the second quarter 2019 compared to the corresponding period in 2018, partially offset by a 3.0% decrease in the average cost of fuel primarily related to lower natural gas and coal prices.

For year-to-date 2019, fuel expense was $689 million compared to $790 million in the corresponding period in 2018. The decrease was primarily due to a 6.9% decrease in the volume of KWHs generated primarily due to scheduled generation outages and milder weather in the first quarter 2019 compared to the corresponding period in 2018, a 6.3% decrease in the average cost of fuel primarily related to lower natural gas and coal prices, and more rainfall for hydro generation in the first quarter 2019.

Purchased Power – Non-Affiliates

In the second quarter 2019, purchased power expense from non-affiliates was $124 million compared to $111 million in the corresponding period in 2018. For year-to-date 2019, purchased power expense from non-affiliates was $242 million compared to $233 million in the corresponding period in 2018. The increases were primarily due to 15.1% and 24.6% increases in the volume of KWHs purchased in the second quarter and year-to-date 2019, respectively, primarily due to scheduled generation outages at Georgia Power-owned generating units, partially offset by 2.3% and 18.7% decreases in the average cost per KWH purchased in the second quarter and year-to-date 2019, respectively, primarily due to lower energy prices.

The volume increases also reflect purchases from Gulf Power which were classified as affiliate prior to January 1, 2019. See Note (K) to the Condensed Financial Statements under "Southern Company" herein for information regarding the sale of Gulf Power.

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.

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Purchased Power – Affiliates

In the second quarter 2019, purchased power expense from affiliates was $134 million compared to $178 million in the corresponding period in 2018. The decrease was primarily due to a 26.4% decrease in the volume of KWHs purchased as Georgia Power units generally dispatched at a lower cost than other Southern Company system resources, partially offset by a 2.9% increase in the average cost per KWH purchased.

For year-to-date 2019, purchased power expense from affiliates was $310 million compared to $349 million in the corresponding period in 2018. The decrease was primarily due to an 11.0% decrease in the average cost per KWH purchased primarily resulting from lower energy prices.

The decreases in purchased power expense from affiliates also reflect the classification of capacity expenses of $6 million and $12 million in the second quarter and year-to-date 2019, respectively, related to PPAs with Southern Power accounted for as finance leases following the adoption of FASB ASC Topic 842, Leases (ASC 842). In 2019, these expenses are included in depreciation and amortization and interest expense, net of amounts capitalized. The changes in the volume of KWHs purchased also include the effect of classifying purchases from Gulf Power as non-affiliate beginning January 1, 2019. See Notes (L) and (K) to the Condensed Financial Statements herein for additional information regarding Georgia Power's adoption of ASC 842 and the sale of Gulf Power, respectively.

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 2019 vs. Second Quarter 2018				Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)		(% change)		(change in millions)		(% change)
$6		1.3		$50		5.8

In the second quarter 2019, other operations and maintenance expenses were $463 million compared to $457 million in the corresponding period in 2018. For year-to-date 2019, other operations and maintenance expenses were $913 million compared to $863 million in the corresponding period in 2018. The increases in the second quarter and year-to-date 2019 reflect adjustments of $8 million and $15 million, respectively, for FERC fees following the conclusion of a multi-year audit of headwater benefits associated with hydro facilities.

The increase in the second quarter 2019 was also due to an increase of $7 million in generation maintenance costs, partially offset by decreases of $5 million in distribution overhead line operation and maintenance costs and $5 million in employee benefit expenses.

The increase for year-to-date 2019 was also due to increases of $14 million in scheduled generation outage expenses, $10 million related to affiliate labor billing credits received in 2018, and $9 million of expenses associated with unregulated new energy conservation project sales, partially offset by a decrease of $7 million in customer accounts and sales expenses.

Depreciation and Amortization

Second Quarter 2019 vs. Second Quarter 2018				Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)		(% change)		(change in millions)		(% change)
$14		6.1		$25		5.5

In the second quarter 2019, depreciation and amortization was $244 million compared to $230 million in the corresponding period in 2018. For year-to-date 2019, depreciation and amortization was $483 million compared to $458 million in the corresponding period in 2018. The increases were primarily due to additional plant in service and reflect the classification of approximately $2 million and $4 million in the second quarter and year-to-date 2019, respectively, related to PPAs with Southern Power accounted for as finance leases following the adoption of

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ASC 842. In prior periods, the expenses related to these PPAs were included in purchased power, affiliates. See Note (L) to the Condensed Financial Statements herein for additional information regarding Georgia Power's adoption of ASC 842.

Estimated Loss on Plant Vogtle Units 3 and 4

Second Quarter 2019 vs. Second Quarter 2018				Year-to-Date 2019 vs. Year-to-Date 2018
(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 did not 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 2 to the financial statements under "Georgia Power – Nuclear Construction" in Item 8 of the Form 10-K for additional information.

Interest Expense, Net of Amounts Capitalized

Second Quarter 2019 vs. Second Quarter 2018				Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)		(% change)		(change in millions)		(% change)
$3		2.9		$(7)		(3.4)

In the second quarter 2019, interest expense, net of amounts capitalized was $105 million compared to $102 million in the corresponding period in 2018. For year-to-date 2019, interest expense, net of amounts capitalized was $201 million compared to $208 million in the corresponding period in 2018. The decrease for year-to-date 2019 was primarily due to a $15 million decrease in interest expense associated with a decrease in average outstanding borrowings, partially offset by the reclassification of $8 million related to PPAs with Southern Power accounted for as finance leases following the adoption of ASC 842. In prior periods, the expenses related to these PPAs were included in purchased power, affiliates. See FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" and "Financing Activities" herein for additional information on borrowings and Note (L) to the Condensed Financial Statements herein for additional information regarding Georgia Power's adoption of ASC 842.

Income Taxes (Benefit)

Second Quarter 2019 vs. Second Quarter 2018				Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)		(% change)		(change in millions)		(% change)
$272		N/M		$261		N/M

N/M - Not meaningful

In the second quarter 2019, income taxes were $129 million compared to an income tax benefit of $143 million in the corresponding period in 2018. For year-to-date 2019, income taxes were $211 million compared to an income tax benefit of $50 million in the corresponding period in 2018. The changes were primarily due to the reduction in pre-tax earnings (loss) in the second quarter 2018 resulting from the charge associated with Plant Vogtle Units 3 and 4 construction, partially offset by an increase in state ITCs. See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" 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

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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, continued customer growth, and the weak pace of growth in electricity use per customer, especially in residential and commercial markets. Plant Vogtle Units 3 and 4 construction and rate recovery are also major factors. 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 GHG strategies to assess upcoming requirements and compliance costs associated with these environmental laws and regulations and to achieve stated goals. Related costs may result from the installation of additional environmental controls, closure and monitoring of CCR facilities, unit retirements, or changing fuel sources for certain existing units, as well as related upgrades to Georgia Power's transmission and distribution systems, and may impact future electric generating unit retirement and replacement decisions, results of operations, cash flows, and/or financial condition. A major portion of these costs is expected to be recovered through retail rates. The ultimate impact of environmental laws and regulations and GHG goals will depend on various factors, such as state adoption and implementation of requirements, the availability and cost of any deployed technology, fuel prices, and the outcome of pending and/or future legal challenges.

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 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/or 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 under "Environmental Remediation" in Item 8 of the Form 10-K for additional information.

Global Climate Issues

On July 8, 2019, the EPA published the final Affordable Clean Energy rule (ACE Rule) to repeal and replace the CPP. Implementation of the CPP has been stayed by the U.S. Supreme Court since 2016. The ACE Rule requires states to develop unit-specific CO₂ emission rate standards for existing coal-fired units based on heat-rate efficiency improvements. Combustion turbines, including natural gas combined cycles, are not included as affected sources in the ACE Rule. Georgia Power has ownership interests in nine coal-fired units to which the ACE Rule is applicable. The ultimate impact of the ACE Rule, including the repeal and replacement of the CPP, to Georgia Power will depend on state implementation plan requirements and the outcome of any associated legal challenges and cannot be determined at this time.

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FERC Matters

See Note 2 to the financial statements under "FERC Matters – Open Access Transmission Tariff" in Item 8 of the Form 10-K for additional information.

On June 28, 2019, the FERC approved a settlement agreement between Alabama Municipal Electric Authority and Cooperative Energy and SCS and the traditional electric operating companies (including Georgia Power) agreeing to an OATT rate reduction based on a 10.6% ROE, with a retroactive effective date of May 10, 2018, and a five-year moratorium on these parties seeking changes to the OATT formula rate. The terms of the OATT settlement agreement will not have a material impact on the financial statements of Georgia Power.

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 Note 2 to the financial statements under "Georgia Power" in Item 8 of the Form 10-K for additional information regarding regulatory matters.

Rate Plans

On June 28, 2019, Georgia Power filed a base rate case (Georgia Power 2019 Base Rate Case) with the Georgia PSC. The filing includes a three-year Alternate Rate Plan with requested rate increases totaling $563 million, $145 million, and $234 million effective January 1, 2020, January 1, 2021, and January 1, 2022, respectively. These increases are based on a proposed retail ROE of 10.90% and a proposed equity ratio of 56% and reflect levelized revenue requirements during the three-year period, with the exception of incremental compliance costs related to CCR AROs, Demand-Side Management programs, and adjustments to the Municipal Franchise Fee tariff.

Georgia Power has requested recovery of the proposed increases through its existing base rate tariffs as follows:

Tariff	2020			2021			2022
	(in millions)
Traditional base:
Levelized	$	209		$	—		$	—
CCR AROs	158			140			227
ECCR	165			—			—
Demand-Side Management	14			2			1
Municipal Franchise Fee	17			3			5
Total(*)	$	563		$	145		$	234

(*)	Totals may not add due to rounding.

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Georgia Power's filing primarily reflects requests to (i) address the impacts of the Tax Reform Legislation, (ii) recover the costs of recent and future capital investments in infrastructure designed to maintain high levels of reliability and superior customer service with updated depreciation rates, (iii) recover substantial storm damage expenses incurred and deferred since 2013 along with a reasonable level of storm damage expenses expected to be incurred during the three years ending December 31, 2022, and (iv) recover the costs necessary to comply with federal and state regulations for CCR AROs. In addition, the filing includes the following provisions:

•	Continuation of an allowed retail ROE range of 10.00% to 12.00%.

•	Continuation of the process whereby two-thirds of any earnings above the top of the allowed ROE range are shared with Georgia Power's customers and the remaining one-third are retained by Georgia Power.

•	Continuation of the option to file an Interim Cost Recovery tariff in the event earnings are projected to fall below the bottom of the ROE range during the three-year term of the plan.

Georgia Power expects the Georgia PSC to issue a final order in this matter on December 17, 2019. The ultimate outcome of this matter cannot be determined at this time.

Integrated Resource Plan

In 2016, the Georgia PSC approved Georgia Power's triennial Integrated Resource Plan, including recovery of costs up to $99 million through June 30, 2019 to preserve nuclear generation as an option at a future generation site in Stewart County, Georgia. In 2017, the Georgia PSC approved Georgia Power's decision to suspend work at the site due to changing economics, including lower load forecasts and fuel costs. In accordance with the Georgia PSC's order, costs incurred of approximately $50 million have been recorded as a regulatory asset.

On July 16, 2019, the Georgia PSC voted to approve Georgia Power's triennial Integrated Resource Plan (2019 IRP) as modified by a stipulated agreement among Georgia Power, the staff of the Georgia PSC, and certain intervenors and further modified by the Georgia PSC.

In the 2019 IRP, the Georgia PSC approved the decertification and retirement of Plant Hammond Units 1 through 4 (840 MWs) and Plant McIntosh Unit 1 (142.5 MWs) effective July 29, 2019. The Georgia PSC also approved the reclassification of the remaining net book values of the Plant Hammond and Plant McIntosh units (approximately $500 million and $40 million, respectively, at June 30, 2019), as well as any unusable materials and supplies inventory balances, upon retirement to a regulatory asset. Recovery of each unit's net book value will continue through December 31, 2019 as provided in the 2013 ARP.

For the regulatory asset balances remaining at December 31, 2019, Georgia Power requested recovery in the Georgia Power 2019 Base Rate Case as follows: (i) the net book values of Plant Mitchell Unit 3 (approximately $8 million at June 30, 2019) and Plant McIntosh Unit 1, any unusable materials and supplies inventory, and the future generation site in Stewart County, Georgia over a three-year period ending December 31, 2022 and (ii) the net book values of Plant Hammond Units 1 through 4 over a period equal to the applicable unit's remaining useful life through 2035. The ultimate outcome of these matters cannot be determined at this time.

Also in the 2019 IRP, the Georgia PSC rejected a request to certify approximately 25 MWs of capacity at Plant Scherer Unit 3 for the retail jurisdiction beginning January 1, 2020 following the expiration of a wholesale PPA. Georgia Power may offer such capacity in the wholesale market or to the retail jurisdiction in a future Integrated Resource Plan. The ultimate outcome of this matter cannot be determined at this time but is not expected to have a material impact on Georgia Power's financial statements.

Additionally, the Georgia PSC approved Georgia Power's proposed environmental compliance strategy associated with ash pond and certain landfill closures and post-closure care in compliance with the CCR Rule and the related state rule. In the Georgia Power 2019 Base Rate Case, Georgia Power requested recovery of the under recovered balance of these compliance costs at December 31, 2019 (approximately $135 million at June 30, 2019) over a three-year period ending December 31, 2022 and recovery of estimated compliance costs of $277 million for 2020, $395 million for 2021, and $655 million for 2022 over three-year periods ending December 31, 2022, 2023, and

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2024, respectively. The ultimate outcome of this matter cannot be determined at this time. See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information regarding Georgia Power's AROs.

The Georgia PSC also approved Georgia Power to (i) issue requests for proposals (RFP) for capacity beginning in 2022 or 2023 and in 2026, 2027, or 2028; (ii) procure up to an additional 2,210 MWs of renewable resources through competitive RFPs; and (iii) invest in a portfolio of up to 80 MWs of battery energy storage technologies.

See "Rate Plans" herein for additional information regarding the Georgia Power 2019 Base Rate Case.

Nuclear Construction

See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding the construction of Plant Vogtle Units 3 and 4, the joint ownership agreements and related funding agreement, VCM reports, and the NCCR tariff.

In 2009, the Georgia PSC certified construction of Plant Vogtle Units 3 and 4. Georgia Power holds a 45.7% ownership interest in 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 other Vogtle Owners, entered into several transitional arrangements to allow construction to continue. In July 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into the Vogtle Services Agreement, whereby 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 provides that it 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, executed the Bechtel Agreement, 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.

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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, 2019(b)	(5.2		)
Remaining estimate to complete(a)	$	3.2

(a)	Excludes financing costs expected to be capitalized through AFUDC of approximately $315 million.

(b)	Net of $1.7 billion received from Toshiba under the Guarantee Settlement Agreement and approximately $188 million in related Customer Refunds.

Georgia Power estimates that its financing costs for construction of Plant Vogtle Units 3 and 4 will total approximately $3.1 billion, of which $2.0 billion had been incurred through June 30, 2019.

In April 2019, Southern Nuclear completed a cost and schedule validation process to verify and update quantities of commodities remaining to install, labor hours to install remaining quantities and related productivity, testing and system turnover requirements, and forecasted staffing needs and related costs. This process confirmed the estimated total project capital cost forecast for Plant Vogtle Units 3 and 4. The expected in-service dates of November 2021 for Unit 3 and November 2022 for Unit 4, as previously approved by the Georgia PSC, remain unchanged.

As construction continues and testing and system turnover activities increase, challenges with management of contractors, subcontractors, and vendors; supervision of craft labor and related craft labor productivity, ability to attract and retain craft labor, and/or related cost escalation; procurement, fabrication, delivery, assembly, and/or installation and the initial testing and start-up, including any required engineering changes, of plant systems, structures, or components (some of which are based on new technology that only recently began initial operation in the global nuclear industry at this scale), or regional transmission upgrades, any of which may require additional labor and/or materials; or other issues could arise and change the projected schedule and estimated cost.

The April 2019 cost and schedule validation process established target values for monthly construction production and system turnover activities as part of a strategy to maintain and, where possible, build margin to the approved in-service dates. To support that strategy, monthly production and activity target values will continue to increase significantly throughout 2019. To meet these increasing monthly targets, existing craft construction productivity must improve and additional craft laborers (particularly electrical and pipefitter craft labor), as well as additional supervision and other field support resources, must be retained and deployed.

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 submittal by Southern Nuclear of the ITAAC documentation for each unit and the related reviews and approvals by the NRC necessary to support NRC authorization to load fuel, 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 regulatory-approved project schedule is currently estimated to result in additional base capital costs of approximately $50

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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 to provide for, among other conditions, additional Vogtle Owner approval requirements. Effective in August 2018, the Vogtle Owners further amended the joint ownership agreements to clarify and provide procedures for certain provisions of the joint ownership agreements related to adverse events that require the vote of the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 to continue construction (as amended, and together with the November 2017 amendment, the Vogtle Joint Ownership Agreements). 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 in conjunction with the nineteenth VCM report, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 were required to vote to continue construction. In September 2018, the Vogtle Owners unanimously voted to continue construction of Plant Vogtle Units 3 and 4.

Amendments to the Vogtle Joint Ownership Agreements

In connection with the vote to continue construction, Georgia Power entered into (i) the Vogtle Owner Term Sheet with the other Vogtle Owners and MEAG's wholly-owned subsidiaries MEAG SPVJ, MEAG Power SPVM, LLC (MEAG SPVM), and MEAG Power SPVP, LLC (MEAG SPVP) to take certain actions which partially mitigate potential financial exposure for the other Vogtle Owners, including additional amendments to the Vogtle Joint Ownership Agreements and the purchase of PTCs from the other Vogtle Owners at pre-established prices, and (ii) the MEAG Term Sheet with MEAG and MEAG SPVJ to provide funding with respect to MEAG SPVJ's ownership interest in Plant Vogtle Units 3 and 4 under certain circumstances. On January 14, 2019, Georgia Power, MEAG, and MEAG SPVJ entered into an agreement to implement the provisions of the MEAG Term Sheet. On February 18, 2019, Georgia Power, the other Vogtle Owners, and MEAG's wholly-owned subsidiaries MEAG SPVJ, MEAG SPVM, and MEAG SPVP entered into certain amendments to the Vogtle Joint Ownership Agreements to implement the provisions of the Vogtle Owner Term Sheet.

The ultimate outcome of these matters 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. At June 30, 2019, Georgia Power had recovered approximately $2.0 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. In December 2018, the Georgia PSC approved Georgia Power's request to increase the NCCR tariff by $88 million annually, effective January 1, 2019.

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

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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) Georgia Power's seventeenth VCM report and modified 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 related 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 $100 million in 2018 and are estimated to have negative earnings impacts of approximately $70 million in 2019 and an aggregate of approximately $630 million from 2020 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.

In February 2018, Georgia Interfaith Power & Light, Inc. (GIPL) and Partnership for Southern Equity, Inc. (PSE) filed a petition appealing the Georgia PSC's January 11, 2018 order with the Fulton County Superior Court. In March 2018, Georgia Watch filed a similar appeal to the Fulton County Superior Court for judicial review of the Georgia PSC's decision and denial of Georgia Watch's motion for reconsideration. In December 2018, the Fulton County Superior Court granted Georgia Power's motion to dismiss the two appeals. On January 9, 2019, GIPL, PSE, and Georgia Watch filed an appeal of this decision with the Georgia Court of Appeals. Georgia Power believes the appeal has no merit; however, an adverse outcome in the appeal combined with subsequent adverse action by the Georgia PSC could have a material impact on Georgia Power's results of operations, financial condition, and liquidity.

In August 2018, Georgia Power filed its nineteenth VCM report with the Georgia PSC, which requested approval of $578 million of construction capital costs incurred from January 1, 2018 through June 30, 2018. On February 19, 2019, the Georgia PSC approved the nineteenth VCM, but deferred approval of $51.6 million of expenditures related to Georgia Power's portion of an administrative claim filed in the Westinghouse bankruptcy proceedings. Through the nineteenth VCM, the Georgia PSC has approved total construction capital costs incurred through June

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30, 2018 of $5.4 billion (before $1.7 billion of payments received under the Guarantee Settlement Agreement and approximately $188 million in related Customer Refunds).

On April 30, 2019, as requested by the staff of the Georgia PSC, Georgia Power reported the results of the cost and schedule validation process to the Georgia PSC. On August 30, 2019, Georgia Power will file its twentieth VCM report concurrently with its twenty-first VCM report with the Georgia PSC, which will reflect the capital cost forecast discussed previously and request approval of $1.2 billion of construction capital costs incurred from June 30, 2018 through June 30, 2019. In addition, on June 20, 2019, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into a settlement agreement related to the administrative claim filed in the Westinghouse bankruptcy proceedings. Accordingly, in the twentieth/twenty-first VCM report, Georgia Power will also request approval of the $51.6 million of associated expenditures previously deferred by the Georgia PSC.

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

See RISK FACTORS of Georgia Power in 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

At June 30, 2019, Georgia Power had borrowed $3.46 billion related to Plant Vogtle Units 3 and 4 costs as provided through the Amended and Restated Loan Guarantee Agreement and related multi-advance credit facilities among Georgia Power, the DOE, and the FFB, which provide for borrowings of up to approximately $5.130 billion, subject to the satisfaction of certain conditions. See Note 8 to the financial statements under "Long-term Debt – 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, and conditions to borrowing.

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

Other Matters

Georgia Power is involved in various other matters that could affect future earnings, including matters being litigated and regulatory matters. 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 other 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 determined at this time; however, for current proceedings not specifically reported in Notes (B) and (C) 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 Notes (B) and (C) 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 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 amounts for municipal franchise fees (which fees are paid 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

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Court, which was granted in 2017. In June 2018, the Georgia Supreme Court affirmed the judgment of the Georgia Court of Appeals and remanded the case to the trial court for further proceedings. Following a motion by Georgia Power, on February 13, 2019, the Superior Court of Fulton County ordered the parties to submit petitions to the Georgia PSC for a declaratory ruling to address certain terms the court previously held were ambiguous as used in the Georgia PSC's orders. The order entered by the Superior Court of Fulton County also conditionally certified the proposed class. In March 2019, Georgia Power and the plaintiffs filed petitions with the Georgia PSC seeking confirmation of the proper application of the municipal franchise fee schedule pursuant to the Georgia PSC's orders. Georgia Power also filed a notice of appeal with the Georgia Court of Appeals regarding the Superior Court of Fulton County's February 2019 order. Georgia Power believes the plaintiffs' claims have no merit. The amount of any possible losses cannot be calculated at this time because, among other factors, it is unknown whether conditional class certification will be upheld and the ultimate composition of any class and whether any losses would be subject to recovery from any municipalities. The ultimate outcome of this matter cannot be determined at this time.

ACCOUNTING POLICIES

Application of Critical Accounting Policies and Estimates

Georgia Power prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Notes 1, 5, and 6 to the financial statements 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.

Recently Issued Accounting Standards

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, 2019. 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 $1.1 billion for the first six months of 2019 and 2018. Net cash used for investing activities totaled $1.8 billion for the first six months of 2019 primarily related to installation of equipment to comply with environmental standards and construction of generation, transmission, and distribution facilities, including approximately $660 million related to the construction of Plant Vogtle Units 3 and 4. Net cash provided from financing activities totaled $620 million for the first six months of 2019 primarily due to borrowings from the FFB for construction of Plant Vogtle Units 3 and 4, the reoffering of pollution control revenue bonds, and an increase in short-term borrowings, partially offset by payment of common stock dividends and the redemption and repurchase of pollution control revenue bonds. 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 2019 include recording $1.5 billion in operating lease right-of-use assets, net of amortization and $1.5 billion in operating lease obligations related to the adoption of ASC 842, an increase of $1.2 billion in property, plant, and equipment to comply with environmental standards and the

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construction of generation, transmission, and distribution facilities, and an increase of $1.2 billion in long-term debt (including securities due within one year) primarily due to borrowings from the FFB for construction of Plant Vogtle Units 3 and 4 and the reoffering of pollution control revenue bonds previously purchased and held by Georgia Power. See Note (L) to the Condensed Financial Statements herein for additional information on the adoption of ASC 842. Also see Notes (B) and (F) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" and "DOE Loan Guarantee Borrowings," respectively, herein for additional information regarding Plant Vogtle Units 3 and 4 and the related Amended and Restated Loan Guarantee Agreement.

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 $988 million will be required through June 30, 2020 to fund maturities of long-term debt. See "Sources of Capital" herein for additional information. Also see FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Nuclear Construction" for additional information regarding Plant Vogtle Units 3 and 4.

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 only recently began initial operation in the global nuclear industry at this 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, delays, increased costs, or inconsistent quality of equipment, materials, and labor; contractor or supplier delay; nonperformance under construction, operating, or other agreements; operational readiness, including specialized operator training and required site safety programs; engineering or design problems; design and other licensing-based compliance matters, including the timely submittal by Southern Nuclear of the ITAAC documentation for each unit and the related reviews and approvals by the NRC necessary to support NRC authorization to load fuel; challenges with start-up activities, including major equipment failure, system integration, or regional transmission upgrades; and/or operational performance. See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Georgia Power – 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 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 a loan guarantee agreement with the DOE and, in March 2019, entered into the Amended and Restated Loan Guarantee Agreement, under which the proceeds of borrowings may be used to

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reimburse Georgia Power for Eligible Project Costs incurred in connection with its construction of Plant Vogtle Units 3 and 4.

Under the Amended and Restated Loan Guarantee Agreement, the DOE has agreed to guarantee the obligations of Georgia Power under note purchase agreements among the DOE, Georgia Power, and the FFB and related promissory notes which provide for two multi-advance term loan facilities (FFB Credit Facilities). Under the FFB Credit Facilities, Georgia Power may make term loan borrowings through the FFB in an amount up to approximately $5.130 billion, provided that total aggregate borrowings under the FFB Credit Facilities may not exceed 70% of (i) Eligible Project Costs minus (ii) approximately $1.492 billion (reflecting the amounts received by Georgia Power under the Guarantee Settlement Agreement less the Customer Refunds). At June 30, 2019, Georgia Power had borrowed $3.46 billion under the FFB Credit Facilities.

See Note (F) to the Condensed Financial Statements under "DOE Loan Guarantee Borrowings" herein for additional information regarding the Amended and Restated Loan Guarantee Agreement, including applicable covenants, events of default, mandatory prepayment events, and additional conditions to borrowing. Also see Note (B) to the Condensed Financial Statements under "Georgia Power – Nuclear Construction" herein for additional information regarding Plant Vogtle Units 3 and 4.

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. At June 30, 2019, Georgia Power's current liabilities exceeded current assets by $2.0 billion primarily due to long-term debt that is due within one year of $988 million and notes payable of $555 million.

At June 30, 2019, Georgia Power had approximately $10 million of cash and cash equivalents and a multi-year committed credit arrangement with banks totaling $1.75 billion, of which $1.74 billion was unused. In May 2019, Georgia Power amended its bank credit arrangement which, among other things, extended the maturity date from 2022 to 2024. This credit arrangement, as well as Georgia Power's term loan arrangements, contain a covenant that limits debt levels and contain a cross-acceleration provision to other indebtedness (including guarantee obligations) of Georgia Power. Such cross-acceleration provisions 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, 2019, Georgia Power was in compliance with this covenant. The 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 8 to the financial statements 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 $1.74 billion unused bank credit arrangement is allocated to provide liquidity support to Georgia Power's pollution control revenue bonds and commercial paper program. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of June 30, 2019 was approximately $550 million. In addition, at June 30, 2019, Georgia Power had $185 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.

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Details of short-term borrowings were as follows:

	Short-term Debt at June 30, 2019							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	$	305			2.7	%		$	288			2.7	%		$	485
Short-term bank debt	250				2.9	%		69				2.9	%		250
Total	$	555			2.8	%		$	357			2.8	%

(*)	Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 2019.

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, 2019, 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, and construction of new generation at Plant Vogtle Units 3 and 4.

The maximum potential collateral requirements under these contracts at June 30, 2019 were as follows:

Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB- and/or Baa3	$	92
Below BBB- and/or Baa3	$	1,040

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

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 Power, may be negatively impacted. A settlement agreement between Georgia Power and the staff of the Georgia PSC regarding the retail rate impact of the Tax Reform Legislation, as approved by the Georgia PSC in April 2018, is expected to help mitigate these potential adverse impacts to certain credit metrics by allowing a higher retail equity ratio through 2019, which Georgia Power has requested to extend in the Georgia Power 2019 Base Rate Case. See Note (B) to the Condensed Financial Statements and Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Rate Plans" for additional information, including requests for additional capital structure adjustments.

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Financing Activities

In January 2019, Georgia Power redeemed approximately $13 million, $20 million, and $75 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 1992, Eighth Series 1994, and Second Series 1995, respectively.

In March 2019, Georgia Power made additional borrowings under the FFB Credit Facilities in an aggregate principal amount of $835 million at an interest rate of 3.213% through the final maturity date of February 20, 2044. The proceeds were used to reimburse Georgia Power for Eligible Project Costs relating to the construction of Plant Vogtle Units 3 and 4.

Also in March 2019, Georgia Power reoffered to the public the following pollution control revenue bonds that previously had been purchased and held by Georgia Power:

•	$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;

•	approximately $105 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

•	$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.

In April 2019, Georgia Power purchased and held the following pollution control revenue bonds. In May 2019, Georgia Power reoffered these pollution control revenue bonds to the public.

•	$55 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Fourth Series 1994;

•	$30 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Fourth Series 1995;

•	$20 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Ninth Series 1994; and

•	$10 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Second Series 1994.

In June 2019, Georgia Power reoffered to the public $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, which had been previously purchased and held by Georgia Power.

Also in June 2019, Georgia Power entered into two short-term floating rate bank loans in aggregate principal amounts of $125 million each, both of which bear interest based on one-month LIBOR. The proceeds from these bank loans were used to repay a portion of Georgia Power's existing indebtedness and for working capital and other general corporate purposes.

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,
	2019				2018				2019				2018
	(in millions)								(in millions)
Operating Revenues:
Retail revenues	$	215			$	212			$	418			$	406
Wholesale revenues, non-affiliates	57				59				114				127
Wholesale revenues, affiliates	37				19				58				54
Other revenues	4				7				10				11
Total operating revenues	313				297				600				598
Operating Expenses:
Fuel	105				98				198				197
Purchased power	6				7				9				16
Other operations and maintenance	68				67				127				141
Depreciation and amortization	48				44				95				84
Taxes other than income taxes	28				27				55				54
Estimated loss on Kemper IGCC	4				—				6				45
Total operating expenses	259				243				490				537
Operating Income	54				54				110				61
Other Income and (Expense):
Interest expense, net of amounts capitalized	(17		)		(21		)		(35		)		(39		)
Other income (expense), net	5				27				11				27
Total other income and (expense)	(12		)		6				(24		)		(12		)
Earnings Before Income Taxes	42				60				86				49
Income taxes	5				13				12				9
Net Income	37				47				74				40
Dividends on Preferred Stock	—				1				—				1
Net Income After Dividends on Preferred Stock	$	37			$	46			$	74			$	39

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	For the Three Months Ended June 30,								For the Six Months Ended June 30,
	2019				2018				2019				2018
	(in millions)								(in millions)
Net Income	$	37			$	47			$	74			$	40
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $-, $-, $-, and $(1), respectively	—				—				—				(1		)
Reclassification adjustment for amounts included in net income, net of tax of $-, $-, $-, and $-, respectively	—				—				1				1
Total other comprehensive income (loss)	—				—				1				—
Comprehensive Income	$	37			$	47			$	75			$	40

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,
	2019				2018
	(in millions)
Operating Activities:
Net income	$	74			$	40
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	98				86
Deferred income taxes	(16		)		289
Settlement of asset retirement obligations	(17		)		(15		)
Estimated loss on Kemper IGCC	11				28
Other, net	1				2
Changes in certain current assets and liabilities —
-Receivables	(8		)		(51		)
-Other current assets	(3		)		(11		)
-Accounts payable	(28		)		(15		)
-Accrued taxes	(43		)		(41		)
-Accrued compensation	(15		)		(14		)
-Other current liabilities	6				(1		)
Net cash provided from operating activities	60				297
Investing Activities:
Property additions	(95		)		(74		)
Construction payables	(12		)		(9		)
Payments pursuant to LTSAs	(11		)		(13		)
Other investing activities	(10		)		(12		)
Net cash used for investing activities	(128		)		(108		)
Financing Activities:
Decrease in notes payable, net	—				(4		)
Proceeds —
Senior notes	—				600
Short-term borrowings	—				300
Capital contributions from parent company	7				1
Pollution control revenue bonds	43				—
Redemptions —
Other long-term debt	—				(900		)
Short-term borrowings	—				(200		)
Return of capital	(75		)		—
Other financing activities	(1		)		(6		)
Net cash used for financing activities	(26		)		(209		)
Net Change in Cash, Cash Equivalents, and Restricted Cash	(94		)		(20		)
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	293				248
Cash, Cash Equivalents, and Restricted Cash at End of Period	$	199			$	228
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $(1) and $- capitalized for 2019 and 2018, respectively)	$	36			$	39
Income taxes, net	23				(257		)
Noncash transactions — Accrued property additions at end of period	23				23

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, 2019				At December 31, 2018
		(in millions)
Current Assets:
Cash and cash equivalents		$	199			$	293
Receivables —
Customer accounts receivable		38				34
Unbilled revenues		44				41
Affiliated		17				21
Other accounts and notes receivable		38				31
Fossil fuel stock		23				20
Materials and supplies		52				53
Other regulatory assets		107				116
Other current assets		13				19
Total current assets		531				628
Property, Plant, and Equipment:
In service		4,800				4,900
Less: Accumulated provision for depreciation		1,427				1,429
Plant in service, net of depreciation		3,373				3,471
Construction work in progress		113				103
Total property, plant, and equipment		3,486				3,574
Other Property and Investments		124				24
Deferred Charges and Other Assets:
Deferred charges related to income taxes		33				33
Regulatory assets – asset retirement obligations		207				143
Other regulatory assets, deferred		328				332
Accumulated deferred income taxes		145				150
Other deferred charges and assets		20				2
Total deferred charges and other assets		733				660
Total Assets		$	4,874			$	4,886

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, 2019				At December 31, 2018
		(in millions)
Current Liabilities:
Securities due within one year		$	300			$	40
Accounts payable —
Affiliated		60				60
Other		49				90
Accrued taxes		52				95
Accrued interest		15				15
Accrued compensation		23				38
Accrued plant closure costs		24				29
Asset retirement obligations		27				34
Other regulatory liabilities		20				12
Over recovered regulatory clause liabilities		12				14
Other current liabilities		52				28
Total current liabilities		634				455
Long-term Debt		1,318				1,539
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		366				378
Deferred credits related to income taxes		362				382
Employee benefit obligations		110				115
Asset retirement obligations, deferred		177				126
Other cost of removal obligations		189				185
Other regulatory liabilities, deferred		79				81
Other deferred credits and liabilities		22				16
Total deferred credits and other liabilities		1,305				1,283
Total Liabilities		3,257				3,277
Common Stockholder's Equity (See accompanying statements)		1,617				1,609
Total Liabilities and Stockholder's Equity		$	4,874			$	4,886

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 COMMON STOCKHOLDER'S EQUITY (UNAUDITED)

	Number of Common Shares Issued			Common Stock				Paid-In Capital				Retained Earnings				Accumulated Other Comprehensive Income (Loss)				Total
	(in millions)
Balance at December 31, 2017	1			$	38			$	4,529			$	(3,205	)		$	(4	)		$	1,358
Net loss after dividends on preferred stock	—			—				—				(7		)		—				(7		)
Capital contributions from parent company	—			—				2				—				—				2
Other comprehensive income (loss)	—			—				—				—				(1		)		(1		)
Other	—			—				—				(1		)		—				(1		)
Balance at March 31, 2018	1			38				4,531				(3,213		)		(5		)		1,351
Net income after dividends on preferred stock	—			—				—				46				—				46
Other	—			—				—				1				—				1
Balance at June 30, 2018	1			$	38			$	4,531			$	(3,166	)		$	(5	)		$	1,398
Balance at December 31, 2018	1			$	38			$	4,546			$	(2,971	)		$	(4	)		$	1,609
Net income	—			—				—				37				—				37
Return of capital to parent company	—			—				(38		)		—				—				(38		)
Capital contributions from parent company	—			—				2				—				—				2
Balance at March 31, 2019	1			38				4,510				(2,934		)		(4		)		1,610
Net income	—			—				—				37				—				37
Return of capital to parent company	—			—				(38		)		—				—				(38		)
Capital contributions from parent company	—			—				8				—				—				8
Balance at June 30, 2019	1			$	38			$	4,480			$	(2,897	)		$	(4	)		$	1,617

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

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SECOND QUARTER 2019 vs. SECOND QUARTER 2018

AND

YEAR-TO-DATE 2019 vs. YEAR-TO-DATE 2018

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 number of customers and to operate in a constructive regulatory environment that provides timely recovery of prudently-incurred costs. These costs include those related to projected long-term demand growth, stringent environmental standards, including CCR rules, reliability, fuel, capital and operations and maintenance expenditures, including expanding and improving transmission and distribution facilities, 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. Mississippi Power is scheduled to file a base rate case in the fourth quarter 2019 (Mississippi Power 2019 Base Rate Case).

On May 7, 2019, the FERC accepted Mississippi Power's March 28, 2019 request for a decrease in wholesale base revenues under the MRA tariff as agreed upon in a settlement agreement reached with its wholesale customers (MRA Settlement Agreement) resolving all matters related to the Kemper County energy facility similar to the retail rate settlement agreement approved by the Mississippi PSC in February 2018 and reflecting the impacts of the Tax Reform Legislation. Pursuant to the MRA Settlement Agreement, base rates decreased $3.7 million annually, effective January 1, 2019. See Note 2 to the financial statements under "FERC Matters" in Item 8 of the Form 10-K for additional information.

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.

RESULTS OF OPERATIONS

Net Income

Second Quarter 2019 vs. Second Quarter 2018				Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)		(% change)		(change in millions)		(% change)
$(9)		(19.6)		$35		89.7

Mississippi Power's net income for the second quarter 2019 was $37 million compared to $46 million for the corresponding period in 2018. This decrease was primarily due to the settlement of Mississippi Power's Deepwater Horizon claim in May 2018 and a decrease in retail revenues due to a new tolling arrangement accounted for as a sales-type lease, partially offset by an increase in PEP rates that became effective for the first billing cycle of September 2018.

For year-to-date 2019, net income was $74 million compared to $39 million for the corresponding period in 2018. This increase was primarily due to lower charges associated with the Kemper IGCC in 2019 and an increase in PEP rates that became effective for the first billing cycle of September 2018, partially offset by a decrease in other income (expense), net due to the settlement of Mississippi Power's Deepwater Horizon claim in May 2018 and a decrease in retail revenues due to a new tolling arrangement accounted for as a sales-type lease.

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Retail Revenues

Second Quarter 2019 vs. Second Quarter 2018				Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)		(% change)		(change in millions)		(% change)
$3		1.4		$12		3.0

In the second quarter 2019, retail revenues were $215 million compared to $212 million for the corresponding period in 2018. For year-to-date 2019, retail revenues were $418 million compared to $406 million for the corresponding period in 2018.

Details of the changes in retail revenues were as follows:

	Second Quarter 2019							Year-to-Date 2019
	(in millions)				(% change)			(in millions)				(% change)
Retail – prior year	$	212						$	406
Estimated change resulting from –
Rates and pricing	11				5.2	%		26				6.4	%
Sales decline	(1		)		(0.5	)		—				—
Weather	—				—			(9		)		(2.2	)
Fuel and other cost recovery	(7		)		(3.3	)		(5		)		(1.2	)
Retail – current year	$	215			1.4	%		$	418			3.0	%

Revenues associated with changes in rates and pricing increased in the second quarter and year-to-date 2019 when compared to the corresponding periods in 2018 primarily due to increases in PEP and ECO Plan rates that became effective for the first billing cycle of September 2018, partially offset by a new tolling arrangement accounted for as a sales-type lease effective January 2019. Partially offsetting the year-to-date 2019 increase was a rate decrease related to the Kemper County energy facility that became effective for the first billing cycle of April 2018. See Note 2 to the financial statements under "Mississippi Power – Performance Evaluation Plan," " – Environmental Compliance Overview Plan," and " – Kemper County Energy Facility – Rate Recovery" in Item 8 of the Form 10-K and Note (L) to the Condensed Financial Statements herein for additional information.

Revenues attributable to changes in sales decreased in the second quarter 2019 when compared to the corresponding period in 2018. Weather-adjusted residential KWH sales increased 0.4% and 1.0% in the second quarter and year-to-date 2019, respectively, due to increased customer usage. Weather-adjusted commercial KWH sales decreased 2.1% and 2.7% in the second quarter and year-to-date 2019, respectively, due to decreased customer usage. Industrial KWH sales decreased 3.1% and 3.5% in the second quarter and year-to-date 2019, respectively, primarily due to decreased customer usage by several large industrial customers.

Revenues associated with weather decreased for year-to-date 2019 when compared to the corresponding period in 2018 primarily due to milder weather.

Fuel and other cost recovery revenues decreased in the second quarter and year-to-date 2019 when compared to the corresponding periods in 2018 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.

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Wholesale Revenues – Non-Affiliates

Second Quarter 2019 vs. Second Quarter 2018				Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)		(% change)		(change in millions)		(% change)
$(2)		(3.4)		$(13)		(10.2)

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.

For year-to-date 2019, wholesale revenues from sales to non-affiliates were $114 million compared to $127 million for the corresponding period in 2018. This decrease primarily resulted from a $6 million decrease in cost-based electric tariff revenues due to decreased customer usage, milder weather, and a decrease in rates due to the MRA Settlement Agreement, a $5 million decrease due to lower PPA capacity and energy sales, and a $3 million decrease due to lower fuel prices, partially offset by a $1 million increase in opportunity sales. See Note (B) to the Condensed Financial Statements under "Mississippi Power – Municipal and Rural Association Tariff" herein for additional information.

Wholesale Revenues – Affiliates

Second Quarter 2019 vs. Second Quarter 2018				Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)		(% change)		(change in millions)		(% change)
$18		94.7		$4		7.4

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

In the second quarter 2019, wholesale revenues from sales to affiliates were $37 million compared to $19 million for the corresponding period in 2018. The increase was primarily due to a $15 million increase associated with higher KWH sales due to the dispatch of Mississippi Power's lower cost generation resources to serve the Southern Company system's territorial load and a $2 million increase associated with a higher average sales price.

For year-to-date 2019, wholesale revenues from sales to affiliates were $58 million compared to $54 million for the corresponding period in 2018. The increase was primarily due to a $25 million increase associated with higher KWH sales due to the dispatch of Mississippi Power's lower cost generation resources to serve the Southern Company system's territorial load, partially offset by a $21 million decrease associated with lower natural gas prices.

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Fuel and Purchased Power Expenses

	Second Quarter 2019 vs. Second Quarter 2018						Year-to-Date 2019 vs. Year-to-Date 2018
	(change in millions)				(% change)		(change in millions)				(% change)
Fuel	$	7			7.1		$	1			0.5
Purchased power	(1		)		(14.3)		(7		)		(43.8)
Total fuel and purchased power expenses	$	6					$	(6	)

In the second quarter 2019, total fuel and purchased power expenses were $111 million compared to $105 million for the corresponding period in 2018. The increase was primarily due to a $13 million net increase associated with the volume of KWHs generated and purchased, partially offset by a net decrease of $7 million associated with lower average cost of fuel.

For year-to-date 2019, total fuel and purchased power expenses were $207 million compared to $213 million for the corresponding period in 2018. The decrease was primarily due to a $13 million decrease related to the average cost of fuel and purchased power primarily due to a lower average cost of natural gas, partially offset by a $7 million net increase associated with the volume of KWHs generated and purchased.

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 2019		Second Quarter 2018		Year-to-Date 2019		Year-to-Date 2018
Total generation (in millions of KWHs)	4,621		4,081		8,570		8,084
Total purchased power (in millions of KWHs)	88		104		139		207
Sources of generation (percent) –
Coal	8		7		6		6
Gas	92		93		94		94
Cost of fuel, generated (in cents per net KWH) –
Coal	3.92		3.42		4.06		3.49
Gas	2.29		2.51		2.37		2.56
Average cost of fuel, generated (in cents per net KWH)	2.43		2.58		2.48		2.61
Average cost of purchased power (in cents per net KWH)	6.53		6.55		6.56		7.77

Fuel

In the second quarter 2019, fuel expense was $105 million compared to $98 million for the corresponding period in 2018. For year-to-date 2019, fuel expense was $198 million compared to $197 million for the corresponding period in 2018. These increases were due to a 14% and 6% increase in the volume of KWHs generated in the second quarter and year-to-date 2019, respectively, partially offset by a 9% and 7% decrease in the average cost of natural gas for the second quarter and year-to-date 2019, respectively.

Purchased Power

For year-to-date 2019, purchased power expense was $9 million compared to $16 million for the corresponding period in 2018. The decrease was primarily due to a 33% decrease in the volume of KWHs purchased due to lower territorial load and a 16% decrease due to a lower average cost of purchased power.

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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 2019 vs. Second Quarter 2018				Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)		(% change)		(change in millions)		(% change)
$1		1.5		$(14)		(9.9)

For year-to-date 2019, other operations and maintenance expenses were $127 million compared to $141 million for the corresponding period in 2018. The decrease was primarily due to decreases of $10 million related to generation maintenance, primarily due to planned outages, and $6 million in employee compensation and benefit expenses due to an employee attrition plan implemented in the third quarter 2018, partially offset by a $4 million increase related to additional overhead line maintenance and vegetation management.

Depreciation and Amortization

Second Quarter 2019 vs. Second Quarter 2018				Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)		(% change)		(change in millions)		(% change)
$4		9.1		$11		13.1

In the second quarter 2019, depreciation and amortization was $48 million compared to $44 million for the corresponding period in 2018. For year-to-date 2019, depreciation and amortization was $95 million compared to $84 million for the corresponding period in 2018. These increases were primarily related to increases in amortization associated with ECO Plan regulatory assets. See Note 2 to the financial statements under "Mississippi Power – Environmental Compliance Overview Plan" in Item 8 of the Form 10-K for additional information.

Estimated Loss on Kemper IGCC

Second Quarter 2019 vs. Second Quarter 2018				Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)		(% change)		(change in millions)		(% change)
$4		N/M		$(39)		(86.7)

N/M - Not meaningful

In the second quarter and year-to-date 2019, estimated losses on the Kemper IGCC were $4 million and $6 million, respectively, compared to an immaterial amount and $45 million, respectively, for the corresponding periods in 2018. These charges relate to abandonment and closure activities for the mine and gasifier-related assets.

See Note 2 to the financial statements under "Mississippi Power – Kemper County Energy Facility" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Mississippi Power – Kemper County Energy Facility" herein for additional information.

Interest Expense, Net of Amounts Capitalized

Second Quarter 2019 vs. Second Quarter 2018				Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)		(% change)		(change in millions)		(% change)
$(4)		(19.0)		$(4)		(10.3)

In the second quarter 2019, interest expense, net of amounts capitalized was $17 million compared to $21 million for the corresponding period in 2018. For year-to-date 2019, interest expense, net of amounts capitalized was $35

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million compared to $39 million for the corresponding period in 2018. These decreases primarily resulted from a decrease in average outstanding debt.

Other Income (Expense), Net

Second Quarter 2019 vs. Second Quarter 2018				Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)		(% change)		(change in millions)		(% change)
$(22)		(81.5)		$(16)		(59.3)

In the second quarter 2019, other income (expense), net was $5 million compared to $27 million for the corresponding period in 2018. For year-to-date 2019, other income (expense), net was $11 million compared to $27 million for the corresponding period in 2018. These decreases were primarily due to a $24 million decrease in the second quarter and year-to-date 2019 due to the settlement of Mississippi Power's Deepwater Horizon claim recorded in May 2018, partially offset by increases of $3 million and $6 million in the second quarter and year-to-date 2019, respectively, due to higher interest income associated with a new tolling arrangement accounted for as a sales-type lease. See Note (L) to the Condensed Financial Statements herein and Note 3 to the financial statements under "Other Matters – Mississippi Power" in Item 8 of the Form 10-K for additional information.

Income Taxes

Second Quarter 2019 vs. Second Quarter 2018				Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)		(% change)		(change in millions)		(% change)
$(8)		(61.5)		$3		33.3

In the second quarter 2019, income taxes were $5 million compared to $13 million for the corresponding period in 2018. This decrease was due to lower pre-tax earnings and an increase in the flowback of excess deferred income taxes as a result of the MRA Settlement Agreement.

For year-to-date 2019, income taxes were $12 million compared to $9 million for the corresponding period in 2018. This increase was primarily due to higher pre-tax earnings resulting from lower estimated losses on the Kemper IGCC, partially offset by an increase in the flowback of excess deferred income taxes as a result of the MRA Settlement Agreement.

See Note (B) to the Condensed Financial Statements under "Mississippi Power" 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 its ability to prevail against legal challenges associated with the Kemper County energy facility. Future earnings will be driven primarily by continued customer growth and the weak pace of growth in electricity use per customer, especially in residential and commercial markets. 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 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.

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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 GHG strategies to assess upcoming requirements and compliance costs associated with these environmental laws and regulations and to achieve stated goals. Related costs may result from the installation of additional environmental controls, closure and monitoring of CCR facilities, unit retirements, or changing fuel sources for certain existing units, as well as related upgrades to Mississippi Power's transmission and distribution systems, and may impact future electric generating unit retirement and replacement decisions, results of operations, cash flows, and/or financial condition. A major portion of these costs is expected to be recovered through retail and wholesale rates. The ultimate impact of environmental laws and regulations and GHG goals will depend on various factors, such as state adoption and implementation of requirements, the availability and cost of any deployed technology, fuel prices, 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 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/or 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 under "Environmental Matters" in Item 8 of the Form 10-K for additional information.

Environmental Laws and Regulations

Coal Combustion Residuals

In June 2019, Mississippi Power recorded an increase of approximately $58 million to its AROs for higher expected compliance costs related to the CCR Rule (and the related State of Alabama rule, as applicable). Approximately $49 million of the revised cost estimates are associated with an ash pond at Plant Greene County, which is jointly owned with Alabama Power. The additional estimated costs to close this ash pond under the planned closure-in-place methodology primarily relate to cost inputs from contractor bids, internal drainage and dewatering system designs, and an increase in the estimated ash volume.

As further analysis is performed and additional details are developed with respect to ash pond closures, Mississippi Power expects to periodically update its ARO cost estimates. Additionally, the closure designs and plans in the State of Alabama are subject to approval by environmental regulatory agencies. 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 this matter cannot be determined at this time. See Note 6 to the financial statements in Item 8 of the Form 10-K and Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information.

Global Climate Issues

On July 8, 2019, the EPA published the final Affordable Clean Energy rule (ACE Rule) to repeal and replace the CPP. Implementation of the CPP has been stayed by the U.S. Supreme Court since 2016. The ACE Rule requires states to develop unit-specific CO₂ emission rate standards for existing coal-fired units based on heat-rate efficiency improvements. Combustion turbines, including natural gas combined cycles, are not included as affected sources in

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the ACE Rule. Mississippi Power has ownership interests in two coal-fired units to which the ACE Rule is applicable. The ultimate impact of the ACE Rule, including the repeal and replacement of the CPP, to Mississippi Power will depend on state implementation plan requirements and the outcome of any associated legal challenges and cannot be determined at this time.

FERC Matters

See Note 2 to the financial statements under "FERC Matters" in Item 8 of the Form 10-K for additional information.

Municipal and Rural Association Tariff

On May 7, 2019, the FERC accepted Mississippi Power's March 28, 2019 request for a decrease in wholesale base revenues under the MRA tariff as agreed upon in the MRA Settlement Agreement resolving all matters related to the Kemper County energy facility similar to the retail rate settlement agreement approved by the Mississippi PSC in February 2018 and reflecting the impacts of the Tax Reform Legislation. Pursuant to the MRA Settlement Agreement, base rates decreased $3.7 million annually, effective January 1, 2019.

Open Access Transmission Tariff

On June 28, 2019, the FERC approved a settlement agreement between Alabama Municipal Electric Authority and Cooperative Energy and SCS and the traditional electric operating companies (including Mississippi Power) agreeing to an OATT rate reduction based on a 10.6% ROE, with a retroactive effective date of May 10, 2018, and a five-year moratorium on these parties seeking changes to the OATT formula rate. The terms of the OATT settlement agreement will not have a material impact on the financial statements of Mississippi Power.

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. Mississippi Power is scheduled to file a base rate case in the fourth quarter 2019.

See Note 2 to the financial statements under "Mississippi Power" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Mississippi Power" herein for additional information.

Environmental Compliance Overview Plan

On July 9, 2019, Mississippi Power filed a request with the Mississippi PSC for a Certificate of Public Convenience and Necessity to complete certain environmental compliance projects, primarily associated with the Plant Daniel coal units co-owned 50% with Gulf Power. The total estimated cost is approximately $125 million, with Mississippi Power's share of approximately $66 million being proposed for recovery through its ECO Plan. Approximately $17 million of Mississippi Power's share is associated with ash pond closure and is reflected in Mississippi Power's ARO liabilities. See Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information on AROs and Note (C) to the Condensed Financial Statements under "Other Matters – Mississippi Power" herein for additional information on Gulf Power's ownership in Plant Daniel.

Kemper County Energy Facility

See Note 2 to the financial statements under "Mississippi Power – Kemper County Energy Facility" in Item 8 of the Form 10-K for additional information.

As the mining permit holder, Liberty Fuels Company, LLC has a legal obligation to perform mine reclamation, and Mississippi Power has a contractual obligation to fund all reclamation activities. As a result of the abandonment of the Kemper IGCC, final mine reclamation began in 2018 and is expected to be substantially completed in 2020,

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with monitoring expected to continue through 2027. See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information.

During the second quarter and year-to-date 2019, Mississippi Power recorded pre-tax charges to income of $4 million ($3 million after tax) and $6 million ($5 million after tax), respectively, primarily resulting from the abandonment and related closure activities and ongoing period costs, net of sales proceeds, 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 at up to $10 million pre-tax (excluding dismantlement costs, net of salvage), may be incurred through the first half of 2020. 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 $7 million for the remainder of 2019 and $2 million to $6 million annually in 2020 through 2023.

In addition, Mississippi Power constructed the CO₂ pipeline for the planned transport of captured CO₂ for use in enhanced oil recovery and is currently evaluating its options regarding the final disposition of the CO₂ pipeline, including removal of the pipeline. This evaluation is expected to be complete later in 2019. If Mississippi Power ultimately decides to remove the CO₂ pipeline, the cost of removal would have a material impact on Mississippi Power's financial statements.

In December 2018, Mississippi Power filed with the DOE its request for property closeout certification under the contract related to the $387 million of grants received. Mississippi Power and the DOE are currently in discussions regarding the requested closeout and property disposition, which may require payment to the DOE for a portion of certain property that is to be retained by Mississippi Power. In connection with the DOE closeout discussions, on April 29, 2019, the Civil Division of the Department of Justice informed Southern Company and Mississippi Power of an investigation related to the Kemper County energy facility. The ultimate outcome of these matters cannot be determined at this time; however, they could have a material impact on Mississippi Power's financial statements.

Other Matters

Mississippi Power is involved in various other matters that could affect future earnings, including matters being litigated and regulatory matters. 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 other 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 determined at this time; however, for current proceedings not specifically reported in Notes (B) and (C) 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 Notes (B) and (C) 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.

In conjunction with Southern Company's sale of Gulf Power, Mississippi Power and Gulf Power have committed to seek a restructuring of their 50% undivided ownership interests in Plant Daniel such that each of them would, after the restructuring, own 100% of a generating unit. On January 15, 2019, Gulf Power provided notice to Mississippi Power that Gulf Power will retire its share of the generating capacity of Plant Daniel on January 15, 2024. Mississippi Power has the option to purchase Gulf Power's ownership interest for $1 on January 15, 2024, provided that Mississippi Power exercises the option no later than 120 days prior to that date. Mississippi Power is assessing the potential operational and economic effects of Gulf Power's notice. The ultimate outcome of these matters remains subject to completion of Mississippi Power's evaluations and applicable regulatory approvals, including by

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the FERC and the Mississippi PSC, and cannot be determined at this time. See Note (K) to the Condensed Financial Statements under "Southern Company" herein for information regarding the sale of Gulf Power.

Litigation

See Note 2 to the financial statements under "Mississippi Power – Kemper County Energy Facility" in Item 8 of the Form 10-K for additional information.

In May 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 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. In the first quarter 2019, Mississippi Power and Southern Company filed motions to dismiss, which were denied by the arbitration panel on May 10, 2019.

In November 2018, Ray C. Turnage and 10 other individual plaintiffs filed a putative class action complaint against Mississippi Power and the three current members of the Mississippi PSC in the U.S. District Court for the Southern District of Mississippi. Mississippi Power received Mississippi PSC approval in 2013 to charge a mirror CWIP rate premised upon including in its rate base pre-construction and construction costs for the Kemper IGCC prior to placing the Kemper IGCC into service. The Mississippi Supreme Court reversed that approval and ordered Mississippi Power to refund the amounts paid by customers under the previously-approved mirror CWIP rate. The plaintiffs allege that the initial approval process, and the amount approved, were improper. They also allege that Mississippi Power underpaid customers by up to $23.5 million in the refund process by applying an incorrect interest rate. The plaintiffs seek to recover, on behalf of themselves and their putative class, actual damages, punitive damages, pre-judgment interest, post-judgment interest, attorney's fees, and costs. In response to Mississippi Power and the Mississippi PSC each filing a motion to dismiss, the plaintiffs filed an amended complaint on March 14, 2019. The amended complaint included four additional plaintiffs and additional claims for gross negligence, reckless conduct, and intentional wrongdoing. Mississippi Power and the Mississippi PSC have each filed a motion to dismiss the amended complaint.

Mississippi Power believes these legal challenges have no merit; however, an adverse outcome in either of these proceedings could have a material impact on Mississippi Power's results of operations, financial condition, and liquidity. The ultimate outcome of these matters 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 Notes 1, 5, and 6 to the financial statements 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.

Recently Issued Accounting Standards

See Note (A) to the Condensed Financial Statements herein for information regarding Mississippi 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 Mississippi Power in Item 7 of the Form 10-K for additional information.

Mississippi Power's cash requirements primarily consist of funding ongoing operations, common stock dividends, 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 and closures of ash ponds, to expand and improve transmission and distribution facilities, and for restoration following major storms.

Net cash provided from operating activities totaled $60 million for the first six months of 2019, a decrease of $237 million as compared to the corresponding period in 2018. The decrease in net cash provided from operating activities is primarily related to lower income tax and ad valorem tax payments and the timing of collections of receivables. Net cash used for investing activities totaled $128 million for the first six months of 2019 primarily due to gross property additions related to distribution and transmission facilities. Net cash used for financing activities totaled $26 million for the first six months of 2019 primarily due to a return of capital to Southern Company, partially offset by $43 million of pollution control revenue bonds reoffered to the public. 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 2019 include a decrease of $221 million in long-term debt, primarily due to the reclassification of $300 million in unsecured senior notes to securities due within one year, partially offset by $43 million in securities reoffered to the public and $40 million in variable rate revenue bonds reclassified from securities due within one year. Other significant changes include a decrease of $100 million in plant in service and an increase of $100 million in other property and investments primarily due to a new tolling arrangement, effective January 1, 2019, accounted for as a sales-type lease; a decrease of $94 million in cash and cash equivalents; and a decrease of $43 million in accrued taxes primarily due to the payment of ad valorem taxes. See Note (L) to the Condensed Financial Statements 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 Mississippi Power in Item 7 of the Form 10-K for a description of Mississippi Power's capital requirements and contractual obligations. Approximately $300 million will be required through June 30, 2020 to fund maturities of long-term debt. See "Sources of Capital" herein for additional information.

The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; 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 to meet its future capital needs from operating cash flows, external securities issuances, borrowings from financial institutions, including commercial paper to the extent Mississippi Power is eligible to participate, and equity contributions from Southern Company. However, the amount, type, and timing of any future financing, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND

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LIQUIDITY – "Capital Requirements and Contractual Obligations" in Item 7 of the Form 10-K for additional information.

As of June 30, 2019, Mississippi Power's current liabilities exceeded current assets by approximately $103 million primarily as a result of $300 million of long-term debt that is due within one year.

At June 30, 2019, Mississippi Power had approximately $199 million of cash and cash equivalents. In June 2019, Mississippi Power entered into a new credit arrangement of $50 million that matures in 2022 and amended its existing credit arrangements, which, among other things, extended the maturity dates from 2019 to 2022. Mississippi Power's committed credit arrangements with banks totaled $150 million at June 30, 2019, all of which was unused.

See Note 8 to the financial statements 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 contain covenants that limit debt levels and typically contain cross-acceleration provisions 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, 2019, 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 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 $150 million unused credit arrangements with banks is allocated to provide liquidity support to Mississippi Power's variable rate revenue bonds. The amount of variable rate revenue bonds outstanding requiring liquidity support as of June 30, 2019 was approximately $40 million.

Short-term debt, including the average amount and maximum amount outstanding, was immaterial at June 30, 2019 and during the three-month period ended June 30, 2019.

Mississippi Power believes the need for working capital can be adequately met by utilizing lines of credit, short-term bank notes, commercial paper to the extent Mississippi Power is eligible to participate, operating cash flows, and other cash.

Credit Rating Risk

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" of Mississippi Power in Item 7 of the Form 10-K for additional information.

At June 30, 2019, Mississippi 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 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, 2019, the maximum potential collateral requirements at a rating below BBB- and/or Baa3 equaled approximately $286 million.

Included in these amounts are certain agreements that could require collateral in the event that either 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 and would be likely to impact the cost at which it does so.

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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 settlement agreement approved by the Mississippi PSC in August 2018 with respect to the 2018 PEP filings and all unresolved PEP filings for prior years 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 Mississippi Power 2019 Base Rate Case. See Note 2 to the financial statements under "Mississippi Power" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Mississippi Power" herein for additional information.

Financing Activities

In March 2019, Mississippi Power reoffered to the public $43 million of Mississippi Business Finance Corporation Pollution Control Revenue Refunding Bonds, Series 2002, which previously had been purchased and held by Mississippi Power.

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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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,
	2019				2018				2019				2018
	(in millions)								(in millions)
Operating Revenues:
Wholesale revenues, non-affiliates	$	390			$	443			$	743			$	867
Wholesale revenues, affiliates	117				109				204				192
Other revenues	3				3				6				5
Total operating revenues	510				555				953				1,064
Operating Expenses:
Fuel	139				153				284				321
Purchased power	32				39				55				100
Other operations and maintenance	79				91				166				184
Depreciation and amortization	119				125				237				240
Taxes other than income taxes	11				12				21				24
Asset impairment	—				119				—				119
Gain on dispositions, net	(23		)		—				(23		)		—
Total operating expenses	357				539				740				988
Operating Income	153				16				213				76
Other Income and (Expense):
Interest expense, net of amounts capitalized	(41		)		(46		)		(84		)		(93		)
Other income (expense), net	40				2				41				5
Total other income and (expense)	(1		)		(44		)		(43		)		(88		)
Earnings (Loss) Before Income Taxes	152				(28		)		170				(12		)
Income taxes (benefit)	(51		)		(73		)		(60		)		(172		)
Net Income	203				45				230				160
Net income attributable to noncontrolling interests	29				23				—				17
Net Income Attributable to Southern Power	$	174			$	22			$	230			$	143

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

 

	For the Three Months Ended June 30,								For the Six Months Ended June 30,
	2019				2018				2019				2018
	(in millions)								(in millions)
Net Income	$	203			$	45			$	230			$	160
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(1), $(19), $(10), and $(3), respectively	(1		)		(55		)		(30		)		(8		)
Reclassification adjustment for amounts included in net income, net of tax of $(2), $20, $6, and $12, respectively	(7		)		59				17				35
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)	(8		)		4				(13		)		28
Comprehensive Income	195				49				217				188
Comprehensive income attributable to noncontrolling interests	29				23				—				17
Comprehensive Income Attributable to Southern Power	$	166			$	26			$	217			$	171

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,
	2019				2018
	(in millions)
Operating Activities:
Net income	$	230			$	160
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	251				256
Deferred income taxes	(63		)		(252		)
Amortization of investment tax credits	(122		)		(29		)
Asset impairment	—				119
Other, net	(69		)		(10		)
Changes in certain current assets and liabilities —
-Receivables	(9		)		(30		)
-Prepaid income taxes	520				(36		)
-Other current assets	4				3
-Accounts payable	(17		)		(41		)
-Accrued compensation	(9		)		(9		)
-Other current liabilities	3				(4		)
Net cash provided from operating activities	719				127
Investing Activities:
Business acquisitions	(2		)		(64		)
Property additions	(123		)		(198		)
Proceeds from dispositions and asset sales	540				—
Change in construction payables	(23		)		2
Investment in unconsolidated subsidiaries	(116		)		—
Payments pursuant to LTSAs	(31		)		(32		)
Other investing activities	9				15
Net cash provided from (used for) investing activities	254				(277		)
Financing Activities:
Decrease in notes payable, net	—				(41		)
Proceeds —
Short-term borrowings	—				200
Capital contributions from parent company	6				16
Redemptions —
Short-term borrowings	(100		)		—
Senior notes	—				(350		)
Other long-term debt	—				(420		)
Return of capital	(505		)		(250		)
Distributions to noncontrolling interests	(82		)		(42		)
Capital contributions from noncontrolling interests	5				1,210
Payment of common stock dividends	(103		)		(156		)
Other financing activities	(5		)		(15		)
Net cash provided from (used for) financing activities	(784		)		152
Net Change in Cash, Cash Equivalents, and Restricted Cash	189				2
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	181				140
Cash, Cash Equivalents, and Restricted Cash at End of Period	$	370			$	142
Supplemental Cash Flow Information:
Cash paid (received) during the period for —
Interest (net of $7 and $10 capitalized for 2019 and 2018, respectively)	$	106			$	109
Income taxes, net	(421		)		109
Noncash transactions — Accrued property additions at end of period	31				33

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, 2019				At December 31, 2018
		(in millions)
Current Assets:
Cash and cash equivalents		$	370			$	181
Receivables —
Customer accounts receivable		153				111
Affiliated		49				55
Other		59				116
Materials and supplies		185				220
Prepaid income taxes		489				25
Other current assets		33				37
Total current assets		1,338				745
Property, Plant, and Equipment:
In service		12,862				13,271
Less: Accumulated provision for depreciation		2,255				2,171
Plant in service, net of depreciation		10,607				11,100
Construction work in progress		419				430
Total property, plant, and equipment		11,026				11,530
Other Property and Investments:
Intangible assets, net of amortization of $60 and $61 at June 30, 2019 and December 31, 2018, respectively		313				345
Other investments		144				—
Total other property and investments		457				345
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization		370				—
Prepaid LTSAs		107				98
Accumulated deferred income taxes		296				1,186
Income taxes receivable, non-current		36				30
Assets held for sale		599				576
Other deferred charges and assets		289				373
Total deferred charges and other assets		1,697				2,263
Total Assets		$	14,518			$	14,883

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, 2019				At December 31, 2018
		(in millions)
Current Liabilities:
Securities due within one year		$	899			$	599
Notes payable		—				100
Accounts payable —
Affiliated		72				92
Other		60				77
Accrued income taxes		23				6
Accrued interest		23				36
Liabilities held for sale		10				15
Other current liabilities		116				106
Total current liabilities		1,203				1,031
Long-term Debt		4,112				4,418
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		106				105
Accumulated deferred ITCs		1,737				1,832
Operating lease obligations		373				—
Other deferred credits and liabilities		169				213
Total deferred credits and other liabilities		2,385				2,150
Total Liabilities		7,700				7,599
Total Stockholders' Equity (See accompanying statements)		6,818				7,284
Total Liabilities and Stockholders' Equity		$	14,518			$	14,883

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 STOCKHOLDERS' EQUITY (UNAUDITED)

	Paid-In Capital				Retained Earnings				Accumulated Other Comprehensive Income (Loss)				Total Common Stockholders' Equity				Noncontrolling Interests				Total
	(in millions)
Balance at December 31, 2017	$	3,662			$	1,478			$	(2	)		$	5,138			$	1,360			$	6,498
Net income attributable to Southern Power	—				121				—				121				—				121
Capital contributions from parent company	1				—				—				1				—				1
Other comprehensive income (loss)	—				—				24				24				—				24
Cash dividends on common stock	—				(78		)		—				(78		)		—				(78		)
Capital contributions from noncontrolling interests	—				—				—				—				9				9
Distributions to noncontrolling interests	—				—				—				—				(13		)		(13		)
Net income (loss) attributable to noncontrolling interests	—				—				—				—				(6		)		(6		)
Other	—				(2		)		5				3				(1		)		2
Balance at March 31, 2018	3,663				1,519				27				5,209				1,349				6,558
Net income attributable to Southern Power	—				22				—				22				—				22
Return of capital to parent company	(250		)		—				—				(250		)		—				(250		)
Capital contributions from parent company	17				—				—				17				—				17
Other comprehensive income (loss)	—				—				4				4				—				4
Cash dividends on common stock	—				(78		)		—				(78		)		—				(78		)
Capital contributions from noncontrolling interests	—				—				—				—				22				22
Distributions to noncontrolling interests	—				—				—				—				(29		)		(29		)
Net income attributable to noncontrolling interests	—				—				—				—				23				23
Sale of noncontrolling interests	(407		)		—				—				(407		)		1,690				1,283
Other	—				1				—				1				1				2
Balance at June 30, 2018	$	3,023			$	1,464			$	31			$	4,518			$	3,056			$	7,574

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CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (UNAUDITED)

	Paid-In Capital				Retained Earnings				Accumulated Other Comprehensive Income (Loss)				Total Common Stockholders' Equity				Noncontrolling Interests				Total
	(in millions)
Balance at December 31, 2018	$	1,600			$	1,352			$	16			$	2,968			$	4,316			$	7,284
Net income attributable to Southern Power	—				56				—				56				—				56
Capital contributions from parent company	1				—				—				1				—				1
Other comprehensive income (loss)	—				—				(4		)		(4		)		—				(4		)
Cash dividends on common stock	—				(51		)		—				(51		)		—				(51		)
Capital contributions from noncontrolling interests	—				—				—				—				3				3
Distributions to noncontrolling interests	—				—				—				—				(41		)		(41		)
Net income (loss) attributable to noncontrolling interests	—				—				—				—				(29		)		(29		)
Other	(1		)		(1		)		—				(2		)		1				(1		)
Balance at March 31, 2019	1,600				1,356				12				2,968				4,250				7,218
Net income attributable to Southern Power	—				174				—				174				—				174
Return of capital to parent company	(505		)		—				—				(505		)		—				(505		)
Capital contributions from parent company	7				—				—				7				—				7
Other comprehensive income (loss)	—				—				(8		)		(8		)		—				(8		)
Cash dividends on common stock	—				(52		)		—				(52		)		—				(52		)
Capital contributions from noncontrolling interests	—				—				—				—				2				2
Distributions to noncontrolling interests	—				—				—				—				(47		)		(47		)
Net income attributable to noncontrolling interests	—				—				—				—				29				29
Other	—				1				—				1				(1		)		—
Balance at June 30, 2019	$	1,102			$	1,479			$	4			$	2,585			$	4,233			$	6,818

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

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SECOND QUARTER 2019 vs. SECOND QUARTER 2018

AND

YEAR-TO-DATE 2019 vs. YEAR-TO-DATE 2018

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, dispositions, and sales of partnership interests, 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 commits to the construction or acquisition of new generating capacity only after entering into or assuming long-term PPAs for the new facilities.

On June 13, 2019, Southern Power completed the sale of its equity interests in Nacogdoches Power, LLC, the owner of an approximately 115-MW biomass facility located in Nacogdoches County, Texas, to Austin Energy, for an aggregate cash purchase price of approximately $461 million, including working capital adjustments.

On June 14, 2019, Southern Power entered into an agreement with Bloom Energy to acquire a majority interest in its affiliate DSGP, which owns and operates fuel cell generation facilities in Delaware, for a total amount not to exceed $173 million. FERC approval of the transfer of the facilities is expected to occur in the third quarter 2019; however, the ultimate outcome of this matter cannot be determined at this time.

On May 4, 2019, Southern Power achieved commercial operation of the 385-MW natural gas expansion unit at Plant Mankato and started providing energy under a PPA with Northern States Power on June 1, 2019. The sale of Plant Mankato to Northern States Power remains subject to state commission approvals and is expected to close in fall 2019. If these state commission approvals are not obtained by October 1, 2019, either party has the option to terminate the sale, which, if elected, would result in the payment of a $15 million termination fee by Northern States Power to Southern Power. The ultimate outcome of this matter cannot be determined at this time.

During the six months ended June 30, 2019, Southern Power continued construction of the 100-MW Wildhorse Mountain and the 200-MW Reading wind facilities. See FUTURE EARNINGS POTENTIAL – "Construction Projects" herein for additional information.

At June 30, 2019, Southern Power's average investment coverage ratio for its generating assets (including Plant Mankato), 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) as the investment amount, was 93% through 2023 and 91% through 2028, with an average remaining contract duration of approximately 15 years.

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 2019 vs. Second Quarter 2018				Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)		(% change)		(change in millions)		(% change)
$152		N/M		$87		60.8

N/M - Not meaningful

Net income attributable to Southern Power for the second quarter 2019 was $174 million compared to $22 million for the corresponding period in 2018. The increase is primarily due to net impacts from the dispositions of Plant Oleander and Plant Stanton Unit A (together, the Florida Plants) in 2018 and Plant Nacogdoches in 2019 (including an asset impairment charge in 2018 and gains on sale, partially offset by decreases in 2019 operating income primarily from PPA capacity revenues) totaling approximately $168 million and net income increases totaling $22 million from a litigation settlement relating to the Roserock solar facility and sales of wind equipment. The increases were partially offset by reductions in net income of approximately $22 million, net, related to the SP Wind tax equity partnership entered into in 2018.

Net income attributable to Southern Power for year-to-date 2019 was $230 million compared to $143 million for the corresponding period in 2018. The increase is primarily due to net impacts from the dispositions of the Florida Plants in 2018 and Plant Nacogdoches in 2019 (including an asset impairment charge in 2018 and gains on sale, partially offset by decreases in 2019 operating income primarily from PPA capacity revenues) totaling approximately $162 million and net income increases totaling $23 million from a litigation settlement relating to the Roserock solar facility and sales of wind equipment. The increases were partially offset by $54 million in state income tax benefits recorded in 2018 arising from the reorganization of Southern Power's legal entities that own and operate certain solar facilities and reductions in net income of approximately $43 million, net, related to the SP Wind tax equity partnership entered into in 2018.

See Notes 7, 10, and 15 to the financial statements in Item 8 of the Form 10-K for additional information on the tax equity partnerships, the legal entity reorganization, and the Florida Plants dispositions, respectively. Also see Note (C) to the Condensed Financial Statements herein for additional information on the Roserock solar facility litigation settlement and Note (K) to the Condensed Financial Statements herein for additional information on the disposition of Plant Nacogdoches and sales of wind equipment.

Operating Revenues

Second Quarter 2019 vs. Second Quarter 2018				Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)		(% change)		(change in millions)		(% change)
$(45)		(8.1)		$(111)		(10.4)

Total operating revenues include PPA capacity revenues, which are derived primarily from long-term contracts involving natural gas facilities and a biomass generating facility (through the sale of Plant Nacogdoches), 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 an accessible wholesale market, or, to the extent those generation assets are part of the FERC-approved IIC, it may sell power into the power pool.

Natural Gas and Biomass Capacity and Energy Revenue

Capacity revenues generally represent the greatest contribution to operating 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

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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 generated from the respective facility and 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.

Details of Southern Power's operating revenues were as follows:

	Second Quarter 2019				Second Quarter 2018				Year-to-Date 2019				Year-to-Date 2018
	(in millions)
PPA capacity revenues	$	125			$	144			$	252			$	282
PPA energy revenues	291				302				518				556
Total PPA revenues	416				446				770				838
Non-PPA revenues	91				106				177				221
Other revenues	3				3				6				5
Total operating revenues	$	510			$	555			$	953			$	1,064

In the second quarter 2019, total operating revenues were $510 million, reflecting a $45 million, or 8%, decrease from the corresponding period in 2018. The decrease in operating revenues was primarily due to the following:

•	PPA capacity revenues decreased $19 million, or 13%, primarily due to decreases totaling $21 million attributable to the sales of the Florida Plants in December 2018 and Plant Nacogdoches in June 2019 and $5 million from the contractual expiration of an affiliate natural gas PPA, partially offset by a $6 million increase in new PPA capacity revenues from existing gas facilities.

•	PPA energy revenues decreased $11 million, or 4%, due to a $7 million decrease related to a decrease in the average cost of fuel and purchased power and a $4 million decrease in sales related to solar and wind facilities primarily driven by a decrease in the volume of KWHs generated.

•	Non-PPA revenues decreased $15 million, or 14%, due to a $16 million decrease in the volume of KWHs sold through short-term sales.

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For year-to-date 2019, total operating revenues were $953 million, reflecting a $111 million, or 10%, decrease from the corresponding period in 2018. The decrease in operating revenues was primarily due to the following:

•	PPA capacity revenues decreased $30 million, or 11%, primarily due to decreases of $38 million attributable to the sales of the Florida Plants in December 2018 and Plant Nacogdoches in June 2019 and $5 million from the contractual expiration of an affiliate natural gas PPA, partially offset by an $11 million increase in new PPA capacity revenues from existing natural gas facilities.

•

PPA energy revenues decreased $38 million, or 7%, primarily due to a $30 million decrease in sales from natural gas facilities, primarily driven by a $51 million decrease in the average cost of fuel and purchased power, partially offset by a $23 million increase in the volume of KWHs sold due to increased customer load, and an $8 million decrease in sales related to solar and wind facilities primarily driven by a decrease in the volume of KWHs generated.

•	Non-PPA revenues decreased $44 million, or 20%, due to a $36 million decrease in the volume of KWHs sold through short-term sales and an $8 million decrease in the market price of energy.

Fuel and Purchased Power Expenses

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

	Second Quarter 2019	Second Quarter 2018		Year-to-Date 2019	Year-to-Date 2018
	(in billions of KWHs)
Generation	11.7	12.2		21.9	22.0
Purchased power	1.0	1.2		1.8	2.2
Total generation and purchased power	12.7	13.4		23.7	24.2
Total generation and purchased power, excluding solar, wind, and tolling agreements	7.1	7.2		13.7	13.9

Southern Power's PPAs for natural gas and biomass generation generally provide that the purchasers are responsible for either procuring the fuel (tolling agreements) or reimbursing Southern Power for substantially all of the cost of fuel relating to the energy delivered under such PPAs. Consequently, 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 2019 vs. Second Quarter 2018						Year-to-Date 2019 vs. Year-to-Date 2018
	(change in millions)				(% change)		(change in millions)				(% change)
Fuel	$	(14	)		(9.2)		$	(37	)		(11.5)
Purchased power	(7		)		(17.9)		(45		)		(45.0)
Total fuel and purchased power expenses	$	(21	)				$	(82	)

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In the second quarter 2019, total fuel and purchased power expenses decreased $21 million, or 10.9%, compared to the corresponding period in 2018. Fuel expense decreased $14 million primarily due to a decrease in the average cost of fuel per KWH generated. Purchased power expense decreased $7 million associated with the volume of KWHs purchased.

For year-to-date 2019, total fuel and purchased power expenses decreased $82 million, or 19%, compared to the corresponding period in 2018. Fuel expense decreased $37 million primarily due to a decrease in the average cost of fuel per KWH generated. Purchased power expense decreased $45 million due to a $25 million decrease associated with the average cost of purchased power and a $20 million decrease associated with the volume of KWHs purchased.

Other Operations and Maintenance Expenses

Second Quarter 2019 vs. Second Quarter 2018				Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)		(% change)		(change in millions)		(% change)
$(12)		(13.2)		$(18)		(9.8)

In the second quarter 2019, other operations and maintenance expenses were $79 million compared to $91 million for the corresponding period in 2018. The decrease was primarily due to a $14 million gain on the sale of wind turbine equipment in the second quarter 2019.

For year-to-date 2019, other operations and maintenance expenses were $166 million compared to $184 million for the corresponding period in 2018. The decrease was primarily due to a $14 million gain on the sale of wind turbine equipment in the second quarter 2019, lower scheduled outage and maintenance expenses, and the recovery of legal costs related to the Roserock litigation settlement in the first quarter 2019.

See Note (K) to the Condensed Financial Statements under "Southern Power – Development Projects" herein for additional information on the sale of wind turbine equipment. Also see Note (C) to the Condensed Financial Statements under "General Litigation Matters – Southern Power" herein for additional information on the Roserock solar facility litigation settlement.

Asset Impairment

In the second quarter 2018, a $119 million asset impairment charge was recorded in anticipation of the sale of the Florida Plants. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Power – Sale of Natural Gas Plants" for additional information.

Gain on Dispositions, net

In the second quarter 2019, the sale of Plant Nacogdoches resulted in a $23 million gain. See Note (K) to the Condensed Financial Statements under "Southern Power" herein for additional information.

Other Income (Expense), net

Second Quarter 2019 vs. Second Quarter 2018				Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)		(% change)		(change in millions)		(% change)
$38		N/M		$36		N/M

N/M - Not meaningful

In the second quarter 2019, other income (expense), net was $40 million compared to $2 million for the corresponding period in 2018. For year-to date 2019, other income (expense), net was $41 million compared to $5 million for the corresponding period in 2018. The increases were primarily due to a $36 million gain arising from the settlement of litigation related to the Roserock solar facility. See Note (C) to the Condensed Financial Statements under "General Litigation Matters – Southern Power" herein for additional information.

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Income Taxes (Benefit)

Second Quarter 2019 vs. Second Quarter 2018				Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)		(% change)		(change in millions)		(% change)
$22		30.1		$112		65.1

In the second quarter 2019, income tax benefit was $51 million compared to $73 million for the corresponding period in 2018. This change was primarily due to a $43 million increase in income tax expense as a result of higher pre-tax earnings and a $41 million reduction of tax benefits from wind PTCs primarily as a result of the 2018 sale of a noncontrolling tax equity interest in SP Wind, partially offset by a $75 million tax benefit resulting from the recognition of deferred ITCs remaining from the original construction of Plant Nacogdoches.

For year-to-date 2019, income tax benefit was $60 million compared to $172 million for the corresponding period in 2018. This change was primarily due to an $80 million reduction of tax benefits from wind PTCs primarily as a result of the sale of a noncontrolling tax equity interest in SP Wind, $54 million in tax benefits recorded in 2018 related to changes in state apportionment rates following the reorganization of Southern Power's legal entities that own and operate certain solar facilities, and a $51 million increase in income tax expense as a result of higher pre-tax earnings, partially offset by a $75 million tax benefit resulting from the recognition of deferred ITCs remaining from the original construction of Plant Nacogdoches.

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

Net Income Attributable to Noncontrolling Interests

Second Quarter 2019 vs. Second Quarter 2018				Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)		(% change)		(change in millions)		(% change)
$6		26.1		$(17)		N/M

N/M - Not meaningful

In the second quarter 2019, net income attributable to noncontrolling interests was $29 million compared to $23 million for the corresponding period in 2018. The increase was primarily due to an allocation of approximately $26 million of income to the noncontrolling interest partner related to the Roserock solar facility litigation settlement, partially offset by $25 million of losses attributable to noncontrolling interests related to the tax equity partnerships entered into in 2018.

For year-to-date 2019, net income attributable to noncontrolling interests was immaterial compared to $17 million for the corresponding period in 2018. The decrease was primarily due to $48 million of losses attributable to noncontrolling interests related to the tax equity partnerships entered into in 2018, partially offset by an allocation of approximately $29 million of income to the noncontrolling interest partner related to the Roserock solar facility litigation settlement.

See Note (C) to the Condensed Financial Statements under "General Litigation Matters – Southern Power" herein and Notes 1 and 7 to the financial statements in Item 8 of the Form 10-K under "General" and "Southern Power," respectively, for additional information.

FUTURE EARNINGS POTENTIAL

The results of operations discussed above are not necessarily indicative of Southern Power's future earnings potential. Future earnings potential will be impacted by the sales of noncontrolling renewable facility interests and the sale of the Florida Plants in 2018, the sale of Plant Nacogdoches in the second quarter 2019, and the pending disposition of Plant Mankato expected in fall 2019. 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

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successful remarketing of capacity as current contracts expire; and Southern Power's ability to execute its growth strategy through the development or acquisition of renewable facilities and other energy projects.

On June 13, 2019, Southern Power completed the sale of its equity interests in Nacogdoches Power, LLC, the owner of an approximately 115-MW biomass facility located in Nacogdoches County, Texas, to Austin Energy, for an aggregate cash purchase price of approximately $461 million, including working capital adjustments. The pre-tax income related to Plant Nacogdoches was $16 million and $13 million for the six months ended June 30, 2019 and 2018, respectively.

On June 14, 2019, Southern Power entered into an agreement with Bloom Energy to acquire a majority interest in its affiliate DSGP, which owns and operates fuel cell generation facilities in Delaware, for a total amount not to exceed $173 million. FERC approval of the transfer of the facilities is expected to occur in the third quarter 2019; however, the ultimate outcome of this matter cannot be determined at this time. See Notes (E) and (K) to the Condensed Financial Statements under "Southern Power – Equity Method Investments" and "Southern Power – Development Projects," respectively, herein for additional information.

On May 4, 2019, Southern Power achieved commercial operation of the 385-MW natural gas expansion unit at Plant Mankato and started providing energy under a PPA with Northern States Power on June 1, 2019. The sale of Plant Mankato to Northern States Power remains subject to state commission approvals and is expected to close in fall 2019. If these state commission approvals are not obtained by October 1, 2019, either party has the option to terminate the sale, which, if elected, would result in the payment of a $15 million termination fee by Northern States Power to Southern Power. The ultimate outcome of this matter cannot be determined at this time. Pre-tax income for Plant Mankato was immaterial for both the six months ended June 30, 2019 and 2018.

Southern Power entered into a tax equity partnership in June 2019 for the Wildhorse Mountain wind facility, with funding of tax equity amounts expected to occur upon commercial operation, which is expected to occur in the fourth quarter 2019. The ultimate outcome of this matter cannot be determined at this time.

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.

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.

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Construction Projects

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Acquisitions" and "Construction Projects" of Southern Power in Item 7 of the Form 10-K and FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein for additional information.

During the six months ended June 30, 2019, Southern Power completed construction of and placed in service the 385-MW Plant Mankato expansion and continued construction of two other projects as described in the table below. Total aggregate construction costs, excluding acquisition costs, are expected to be between $405 million and $450 million for the Wildhorse Mountain and Reading facilities. At June 30, 2019, total costs of construction incurred for these projects were $186 million and are included in CWIP. 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 Completed During the Six Months Ended June 30, 2019
Mankato expansion(a)	Natural Gas	385	Mankato, MN	May 2019	Northern States Power Company	20 years
Projects Under Construction as of June 30, 2019
Wildhorse Mountain(b)	Wind	100	Pushmataha County, OK	Fourth quarter 2019	Arkansas Electric Cooperative	20 years
Reading(c)	Wind	200	Osage and Lyon Counties, KS	Second quarter 2020	Royal Caribbean Cruises LTD	12 years

(a)	In November 2018, Southern Power entered into an agreement to sell all of its equity interests in Plant Mankato, including this expansion that was completed during May 2019. This transaction is subject to state commission approvals and is expected to close in fall 2019. The expansion unit started providing energy under a PPA with Northern States Power on June 1, 2019.

(b)	In May 2018, Southern Power purchased 100% of the Wildhorse Mountain facility. Southern Power entered into a tax equity partnership in June 2019 with funding of tax equity amounts expected to occur upon commercial operation.

(c)	In August 2018, Southern Power purchased 100% of the membership interests of the Reading facility from the joint development arrangement with Renewable Energy Systems Americas, Inc. Southern Power may enter into a tax equity partnership, in which case it would then own 100% of the class B membership interests.

Development Projects

See Note 15 to the financial statements under "Southern Power – Development Projects" in Item 8 of the Form 10-K for additional information.

Southern Power continues to evaluate and refine the deployment of wind turbine equipment purchased in 2016 and 2017 to potential joint development and construction projects as well as the amount of MW capacity to be constructed. During the six months ended June 30, 2019, certain wind turbine equipment was sold, resulting in a gain on the sale of approximately $14 million.

Other Matters

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Other Matters" and "Power Sales Agreements – General" of Southern Power in Item 7 for additional information.

Southern Power is involved in various other matters that could affect future earnings, including matters being litigated, as well as other regulatory and business matters. 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 other 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

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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, regulatory matters, or other business matters cannot be determined at this time; however, for current proceedings not specifically reported in Notes (B) and (C) 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.

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 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 connection therewith, Southern Power withheld payment of approximately $26 million to the construction contractor, which placed a lien on the Roserock facility for the same amount. In 2017, Roserock filed a lawsuit in the state district court in Pecos County, Texas against XL Insurance America, Inc. and North American Elite Insurance Company seeking recovery from an insurance policy for damages resulting from the hail event and McCarthy's installation practices. In June 2018, the court 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. Separate lawsuits were filed between Roserock and McCarthy, as well as other parties, and that litigation was consolidated in the U.S. District Court for the Western District of Texas. On April 18, 2019, Roserock and the parties to the state and federal lawsuits executed a settlement agreement and mutual release that resolved both lawsuits. Following execution of the agreement, the lawsuits were dismissed, Southern Power paid McCarthy the amounts previously withheld, and McCarthy released its lien. As part of the settlement, Roserock received funds that covered all related legal costs, damages, and the replacement costs of certain solar panels. Funds received by Southern Power in excess of the initial replacement costs were recognized as a gain and included in other income (expense), net in 2019. A portion of the pre-tax gain was allocated to noncontrolling interests and Southern Power recognized a $12 million after-tax gain.

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 Notes 1, 4, and 10 to the financial statements 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 Note (A) to the Condensed Financial Statements herein for information regarding Southern Power's recently adopted accounting standards.

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, 2019. 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.

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Southern Power also utilizes tax equity partnerships, where the tax partner takes significantly all of the federal tax benefits, as a financing source. These tax equity partnerships are consolidated in Southern Power's financial statements and are accounted for using a HLBV methodology to allocate partnership gains and losses. During the first six months of 2019, Southern Power did not receive any material tax equity funding amounts. See Note 1 to the financial statements under "Hypothetical Liquidation at Book Value" in Item 8 of the Form 10-K for additional information on the HLBV methodology.

Net cash provided from operating activities totaled $719 million for the first six months of 2019 compared to $127 million for the first six months of 2018. The increase in net cash provided from operating activities was primarily due to the utilization of income tax credits of $520 million in 2019. Net cash provided from investing activities totaled $254 million for the first six months of 2019 primarily due to proceeds from the disposition of Plant Nacogdoches and wind equipment sales, partially offset by Southern Power's investment in DSGP and ongoing construction activities. Net cash used for financing activities totaled $784 million for the first six months of 2019 primarily due to returns of capital to Southern Company, common stock dividends, the repayment of a short-term bank loan, and distributions to noncontrolling interests. 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 2019 include a $464 million increase in prepaid income taxes due to the expected utilization of tax credits for the remainder of the 2019 tax year, a $493 million decrease in plant in service primarily as a result of the sale of Plant Nacogdoches, a $370 million increase in operating lease right-of-use assets along with a corresponding increase in operating lease obligations of $373 million due to the adoption of ASU No. 2016-02, a $144 million increase in other investments primarily related to Southern Power's investment in DSGP, and a $466 million decrease in stockholder's equity primarily due to returns of capital to Southern Company. See Note (K) under "Southern Power" and Note (L) to the Condensed Financial Statements herein for additional information.

See FUTURE EARNINGS POTENTIAL – "Construction Projects" 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. Approximately $900 million will be required through June 30, 2020 to fund maturities of long-term debt. See "Sources of Capital" herein for additional information.

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. Actual construction costs, including acquisitions, 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 – "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.

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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), borrowings from financial institutions, equity contributions from Southern Company, external securities issuances, and operating cash flows.

As of June 30, 2019, Southern Power had cash and cash equivalents of approximately $370 million.

Southern Power's commercial paper program is used to finance acquisition and construction costs related to electric generating facilities and for general corporate purposes, including maturing debt. Commercial paper is included in notes payable on the condensed consolidated balance sheets.

Details of short-term borrowings were as follows:

	Short-term Borrowings During the Period (*)
	Average Amount Outstanding				Weighted Average Interest Rate			Maximum Amount Outstanding
	(in millions)							(in millions)
Commercial paper	$	7			2.6	%		$	75
Short-term loans	58				3.1	%		100
Total	$	65			3.0	%

(*)	Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 2019. No short-term debt was outstanding at June 30, 2019.

In May 2019, Southern Power amended and restated its committed credit facility (Facility) to extend the maturity date to 2024 and decrease the borrowing capacity from $750 million to $600 million. At June 30, 2019, $39 million of the Facility had been used for letters of credit and $561 million remains unused. 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 8 to the financial statements 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 Facility 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 2021 for standby letters of credit. At June 30, 2019, $90 million has been used for letters of credit, primarily as credit support for PPA requirements, and $30 million remains unused.

In addition, at June 30, 2019, Southern Power had $104 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.

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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, 2019 were as follows:

Credit Ratings	Maximum Potential Collateral Requirements
	(in millions)
At BBB and/or Baa2	$	29
At BBB- and/or Baa3	$	339
At BB+ and/or Ba1(*)	$	1,054

(*)	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 either 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.

Financing Activities

In May 2019, Southern Power repaid at maturity a $100 million short-term floating rate bank loan.

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,
	2019				2018				2019				2018
	(in millions)								(in millions)
Operating Revenues:
Natural gas revenues (includes revenue taxes of $23, $23, $78, and $74, respectively)	$	688			$	710			$	2,163			$	2,341
Alternative revenue programs	1				(4		)		—				(27		)
Other revenues	—				24				—				55
Total operating revenues	689				730				2,163				2,369
Operating Expenses:
Cost of natural gas	191				228				877				949
Cost of other sales	—				5				—				12
Other operations and maintenance	199				238				433				514
Depreciation and amortization	119				126				238				255
Taxes other than income taxes	46				48				128				125
Goodwill impairment	—				—				—				42
Loss on disposition	—				36				—				36
Total operating expenses	555				681				1,676				1,933
Operating Income	134				49				487				436
Other Income and (Expense):
Earnings from equity method investments	31				31				80				74
Interest expense, net of amounts capitalized	(59		)		(59		)		(118		)		(118		)
Other income (expense), net	6				3				10				15
Total other income and (expense)	(22		)		(25		)		(28		)		(29		)
Earnings Before Income Taxes	112				24				459				407
Income taxes	6				55				83				159
Net Income (Loss)	$	106			$	(31	)		$	376			$	248

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

 

	For the Three Months Ended June 30,								For the Six Months Ended June 30,
	2019				2018				2019				2018
	(in millions)								(in millions)
Net Income (Loss)	$	106			$	(31	)		$	376			$	248
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(1), $-, $(1), and $-, respectively	(3		)		1				(3		)		1
Reclassification adjustment for amounts included in net income, net of tax of $-, $-, $-, and $1, respectively	—				—				—				2
Pension and other postretirement benefit plans:
Reclassification adjustment for amounts included in net income, net of tax of $(1), $-, $(1), and $-, respectively	—				—				(1		)		—
Total other comprehensive income (loss)	(3		)		1				(4		)		3
Comprehensive Income (Loss)	$	103			$	(30	)		$	372			$	251

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,
	2019				2018
	(in millions)
Operating Activities:
Net income	$	376			$	248
Adjustments to reconcile net income to net cash provided from operating activities —
Depreciation and amortization, total	238				255
Deferred income taxes	59				(12		)
Mark-to-market adjustments	30				2
Goodwill impairment	—				42
Loss on disposition	—				36
Other, net	(26		)		(24		)
Changes in certain current assets and liabilities —
-Receivables	717				504
-Natural gas for sale, net of temporary LIFO liquidation	256				295
-Other current assets	29				41
-Accounts payable	(604		)		(125		)
-Accrued taxes	(54		)		38
-Accrued compensation	(34		)		(6		)
-Other current liabilities	(56		)		24
Net cash provided from operating activities	931				1,318
Investing Activities:
Property additions	(603		)		(679		)
Cost of removal, net of salvage	(33		)		(18		)
Change in construction payables, net	26				(6		)
Investment in unconsolidated subsidiaries	(18		)		(60		)
Proceeds from dispositions and asset sales	32				364
Other investing activities	10				18
Net cash used for investing activities	(586		)		(381		)
Financing Activities:
Decrease in notes payable, net	(158		)		(515		)
Redemptions — Gas facility revenue bonds	—				(200		)
Payment of common stock dividends	(235		)		(235		)
Other financing activities	38				10
Net cash used for financing activities	(355		)		(940		)
Net Change in Cash, Cash Equivalents, and Restricted Cash	(10		)		(3		)
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period	70				78
Cash, Cash Equivalents, and Restricted Cash at End of Period	$	60			$	75
Supplemental Cash Flow Information:
Cash paid during the period for —
Interest (net of $3 and $3 capitalized for 2019 and 2018, respectively)	$	125			$	129
Income taxes, net	96				106
Noncash transactions — Accrued property additions at end of period	123				129

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, 2019				At December 31, 2018
		(in millions)
Current Assets:
Cash and cash equivalents		$	56			$	64
Receivables —
Energy marketing receivables		361				801
Customer accounts receivable		281				370
Unbilled revenues		63				213
Affiliated		10				11
Other accounts and notes receivable		100				142
Accumulated provision for uncollectible accounts		(31		)		(30		)
Natural gas for sale		268				524
Prepaid expenses		120				118
Assets from risk management activities, net of collateral		101				219
Other regulatory assets		56				73
Other current assets		44				50
Total current assets		1,429				2,555
Property, Plant, and Equipment:
In service		15,680				15,177
Less: Accumulated depreciation		4,522				4,400
Plant in service, net of depreciation		11,158				10,777
Construction work in progress		628				580
Total property, plant, and equipment		11,786				11,357
Other Property and Investments:
Goodwill		5,015				5,015
Equity investments in unconsolidated subsidiaries		1,509				1,538
Other intangible assets, net of amortization of $161 and $145 at June 30, 2019 and December 31, 2018, respectively		85				101
Miscellaneous property and investments		20				20
Total other property and investments		6,629				6,674
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization		95				—
Other regulatory assets, deferred		636				669
Other deferred charges and assets		186				193
Total deferred charges and other assets		917				862
Total Assets		$	20,761			$	21,448

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, 2019				At December 31, 2018
		(in millions)
Current Liabilities:
Securities due within one year		$	351			$	357
Notes payable		492				650
Energy marketing trade payables		393				856
Accounts payable —
Affiliated		38				45
Other		294				402
Customer deposits		92				133
Accrued taxes —
Accrued income taxes		17				66
Other accrued taxes		70				75
Accrued interest		57				55
Accrued compensation		64				100
Liabilities from risk management activities, net of collateral		22				76
Other regulatory liabilities		97				79
Other current liabilities		124				130
Total current liabilities		2,111				3,024
Long-term Debt		5,565				5,583
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		1,088				1,016
Deferred credits related to income taxes		910				940
Employee benefit obligations		354				357
Operating lease obligations		79				—
Other cost of removal obligations		1,598				1,585
Accrued environmental remediation		247				268
Other deferred credits and liabilities		50				105
Total deferred credits and other liabilities		4,326				4,271
Total Liabilities		12,002				12,878
Common Stockholder's Equity (See accompanying statements)		8,759				8,570
Total Liabilities and Stockholder's Equity		$	20,761			$	21,448

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 STOCKHOLDER'S EQUITY (UNAUDITED)

	Paid-In Capital				Retained Earnings (Accumulated Deficit)				Accumulated Other Comprehensive Income (Loss)				Total
	(in millions)
Balance at December 31, 2017	$	9,214			$	(212	)		$	20			$	9,022
Net income	—				279				—				279
Capital contributions from parent company	14				—				—				14
Other comprehensive income (loss)	—				—				2				2
Cash dividends on common stock	—				(118		)		—				(118		)
Other	—				(4		)		4				—
Balance at March 31, 2018	9,228				(55		)		26				9,199
Net loss	—				(31		)		—				(31		)
Capital contributions from parent company	8				—				—				8
Other comprehensive income (loss)	—				—				1				1
Cash dividends on common stock	—				(117		)		—				(117		)
Other	—				1				—				1
Balance at June 30, 2018	$	9,236			$	(202	)		$	27			$	9,061
Balance at December 31, 2018	$	8,856			$	(312	)		$	26			$	8,570
Net income	—				270				—				270
Capital contributions from parent company	17				—				—				17
Other comprehensive income (loss)	—				—				(1		)		(1		)
Cash dividends on common stock	—				(118		)		—				(118		)
Balance at March 31, 2019	8,873				(160		)		25				8,738
Net income	—				106				—				106
Capital contributions from parent company	35				—				—				35
Other comprehensive income (loss)	—				—				(3		)		(3		)
Cash dividends on common stock	—				(117		)		—				(117		)
Balance at June 30, 2019	$	8,908			$	(171	)		$	22			$	8,759

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

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

SECOND QUARTER 2019 vs. SECOND QUARTER 2018

AND

YEAR-TO-DATE 2019 vs. YEAR-TO-DATE 2018

OVERVIEW

Southern Company Gas is an energy services holding company whose primary business is the distribution of natural gas through utilities in four states – Nicor Gas in Illinois, Atlanta Gas Light in Georgia, Virginia Natural Gas in Virginia, and Chattanooga Gas in Tennessee. Southern Company Gas is also involved in several other complementary businesses.

Southern Company Gas manages its business through four reportable segments – gas distribution operations, gas pipeline investments, wholesale gas services, and gas marketing services – and one non-reportable segment, all other. See Note (M) to the Condensed Financial Statements herein and "BUSINESS – The Southern Company System – Southern Company Gas" in Item 1 of the Form 10-K for additional information.

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, safety, reliability, resilience, 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.

Atlanta Gas Light filed a rate case on June 3, 2019 and Nicor Gas filed a rate case in November 2018. Both rate cases are expected to be finalized in 2019. The ultimate outcome of these matters cannot be determined at this time. See FUTURE EARNINGS POTENTIAL – "Regulatory Matters" herein and Note 2 to the financial statements under "Southern Company Gas – Rate Proceedings" in Item 8 of the Form 10-K for additional information.

During 2018, Southern Company Gas completed the following sales, resulting in approximately $2.7 billion in aggregate proceeds.

•	On June 4, 2018, Southern Company Gas completed the stock sale of Pivotal Home Solutions to American Water Enterprises LLC.

•	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.

•	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.

See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company Gas" for additional information on these dispositions.

Operating Metrics

Southern Company Gas continues to focus on several operating metrics, including Heating Degree Days, customer count, and volumes of natural gas sold.

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

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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 operating revenues from utility customers in Illinois and 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 limit the negative income impacts in the event of warmer-than-normal weather, while retaining a significant portion of the positive benefits of colder-than-normal weather 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.

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

During the Heating Season, 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 payables. 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 2019 vs. Second Quarter 2018				Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)		(% change)		(change in millions)		(% change)
$137		N/M		$128		51.6

N/M - Not meaningful

In the second quarter 2019, net income was $106 million compared to a net loss of $31 million for the corresponding period in 2018. Excluding a $73 million net loss in 2018 from the Southern Company Gas Dispositions and $7 million net income in 2019 from the sale of Triton, net income increased $57 million. This increase was primarily due to an increase of $44 million at wholesale gas services primarily due to significant gas price volatility during the second quarter 2018, continued investment in infrastructure replacement programs, and lower income taxes, primarily at Atlanta Gas Light due to increased flowback of excess deferred income taxes in lieu of a rate increase as previously authorized by the Georgia PSC.

For year-to-date 2019, net income was $376 million compared to $248 million for the corresponding period in 2018. Excluding an $81 million net loss in 2018 from the Southern Company Gas Dispositions and $7 million net income in 2019 from the sale of Triton, net income increased $40 million. This increase was primarily due to continued investment in infrastructure replacement programs and base rate changes, lower income taxes primarily at Atlanta Gas Light due to increased flowback of excess deferred income taxes in lieu of a rate increase as previously authorized by the Georgia PSC, the impact of adopting a new paid time off policy to align with the Southern Company system in first quarter 2018, and an increase in earnings from equity method investments in 2019. Partially offsetting these increases were a decrease of $13 million at wholesale gas services, a contractor litigation

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settlement recorded in the first quarter 2018, and increased depreciation and amortization primarily due to continued infrastructure investments at gas distribution operations.

See Note 2 to the financial statements under "Southern Company Gas – Rate Proceedings – Atlanta Gas Light" and " – Infrastructure Replacement Programs and Capital Projects – Atlanta Gas Light – PRP" in Item 8 of the Form 10-K for additional information on Atlanta Gas Light's stipulation reflecting the impacts of the Tax Reform Legislation and the contractor litigation settlement, respectively.

Natural Gas Revenues, including Alternative Revenue Programs

Second Quarter 2019 vs. Second Quarter 2018				Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)		(% change)		(change in millions)		(% change)
$(17)		(2.4)		$(151)		(6.5)

In the second quarter 2019, natural gas revenues, including alternative revenue programs, were $689 million compared to $706 million for the corresponding period in 2018. For year-to-date 2019, natural gas revenues, including alternative revenue programs, were $2.2 billion compared to $2.3 billion for the corresponding period in 2018.

Details of the changes in natural gas revenues, including alternative revenue programs, were as follows:

	Second Quarter 2019							Year-to-Date 2019
	(in millions)				(% change)			(in millions)				(% change)
Natural gas revenues – prior year	$	706						$	2,314
Estimated change resulting from –
Infrastructure replacement programs and base rate changes	10				1.4	%		42				1.8	%
Gas costs and other cost recovery	(13		)		(1.8	)		49				2.1
Weather	(7		)		(1.1	)		—				—
Wholesale gas services	64				9.1			(16		)		(0.7	)
Southern Company Gas Dispositions	(70		)		(9.9	)		(237		)		(10.2	)
Other	(1		)		(0.1	)		11				0.5
Natural gas revenues – current year	$	689			(2.4	)%		$	2,163			(6.5	)%

Revenues from infrastructure replacement programs and base rate changes increased in the second quarter and year-to-date 2019 compared to the corresponding periods in 2018 primarily due to increases of $4 million and $25 million, respectively, at Nicor Gas and $5 million and $14 million, respectively, at Atlanta Gas Light. These amounts include gas distribution operations' continued investments recovered through infrastructure replacement programs and base rate increases as well as the effect of revenues deferred in 2018 as a result of the Tax Reform Legislation. See Note 2 to the financial statements under "Southern Company Gas – Rate Proceedings" in Item 8 of the Form 10-K for additional information.

Revenues associated with gas costs and other cost recovery decreased in the second quarter 2019 and increased year-to-date 2019 compared to the corresponding periods in 2018. The decrease in the second quarter 2019 is primarily due to lower natural gas prices and decreased volumes of natural gas sold. The increase for year-to-date 2019 is primarily due to increased natural gas prices in the first quarter 2019, partially offset by decreased volumes of natural gas sold year-to-date 2019. 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 "Cost of Natural Gas" herein for additional information. Revenue impacts from weather and customer growth are described further below.

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Revenues decreased in the second quarter 2019 due to warmer weather in Illinois and Georgia compared to the corresponding period in 2018. See the weather discussion herein for additional information.

Revenues from wholesale gas services increased in the second quarter 2019 and decreased year-to-date 2019 compared to the corresponding periods in 2018. The increase in the second quarter 2019 is primarily due to derivative gains, partially offset by decreased commercial activity. For year-to-date 2019, the decrease is primarily due to decreased commercial activity, partially offset by derivative gains. See "Segment Information – Wholesale Gas Services" herein for additional information.

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 Heating Degree Days information for Illinois and Georgia, the primary locations where Southern Company Gas' operations are impacted by weather.

	Second Quarter							2019 vs. 2018		2019 vs. normal			Year-to-Date							2019 vs. 2018		2019 vs. normal
	Normal(*)		2019		2018			(warmer)		colder (warmer)			Normal(*)		2019		2018			colder (warmer)		colder (warmer)
Illinois	635		659		767			(14.1	)%	3.8	%		3,679		3,956		3,809			3.9	%	7.5	%
Georgia	124		86		175			(50.9	)%	(30.6	)%		1,566		1,298		1,539			(15.7	)%	(17.1	)%

(*)	Normal represents the 10-year average from January 1, 2009 through June 30, 2018 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. The remaining impacts of weather on earnings are reflected in the chart below.

	Gas Distribution Operations														Gas Marketing Services
	Second Quarter							Year-to-Date							Second Quarter							Year-to-Date
	2019			2018				2019			2018				2019			2018				2019			2018
	(in millions)														(in millions)
Pre-tax	$	—		$	4			$	2		$	2			$	(1	)	$	2			$	(1	)	$	(1	)
After tax	—			3				2			2				(1		)	1				(1		)	(1		)

The following table provides the number of customers served by Southern Company Gas at June 30, 2019 and 2018:

	June 30,
	2019			2018			2019 vs. 2018
	(in thousands, except market share %)						(% change)
Gas distribution operations(a)	4,231			4,609			(8.2	)%
Gas marketing services
Energy customers(b)	622			696			(10.6	)%
Market share of energy customers in Georgia	28.8	%		29.4	%

(a)	Includes total customers of approximately 407,000 at June 30, 2018 related to Elizabethtown Gas, Elkton Gas, and Florida City Gas, which were sold in July 2018. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company Gas" for additional information.

(b)	Gas marketing services' customers are primarily located in Georgia and Illinois. Also included as of June 30, 2018 were approximately 70,000 customers in Ohio contracted through an annual auction process to serve for 12 months beginning April 1, 2018.

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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.

Other Revenues

Second Quarter 2019 vs. Second Quarter 2018				Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)		(% change)		(change in millions)		(% change)
$(24)		(100.0)		$(55)		(100.0)

Other revenues related to Pivotal Home Solutions, which was sold in June 2018. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company Gas – Sale of Pivotal Home Solutions" for additional information.

Cost of Natural Gas

Second Quarter 2019 vs. Second Quarter 2018				Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)		(% change)		(change in millions)		(% change)
$(37)		(16.2)		$(72)		(7.6)

Excluding Atlanta Gas Light, which does not sell natural gas to end-use customers, 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 80% and 85% of total cost of natural gas for the second quarter and year-to-date 2019, respectively. See MANAGEMENT'S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS – "Cost of Natural Gas" of Southern Company Gas in Item 7 of the Form 10-K and "Natural Gas Revenues, including Alternative Revenue Programs" herein for additional information.

In the second quarter 2019, cost of natural gas was $191 million compared to $228 million for the corresponding period in 2018. Excluding a $25 million decrease related to the Southern Company Gas Dispositions, cost of natural gas decreased $12 million. This decrease reflects a 5.7% decrease in natural gas prices and a decrease in the volume of natural gas sold in the second quarter 2019 primarily as a result of warmer weather in Illinois and Georgia compared to the corresponding period in 2018.

For year-to-date 2019, cost of natural gas was $877 million compared to $949 million for the corresponding period in 2018. Excluding a $104 million decrease related to the Southern Company Gas Dispositions, cost of natural gas increased $32 million. This increase reflects an increase in natural gas prices, partially offset by a decrease in the volume of natural gas sold year-to-date 2019 compared to the corresponding period in 2018.

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The following table details the volumes of natural gas sold during all periods presented.

	Second Quarter				2019 vs. 2018			Year-to-Date				2019 vs. 2018
	2019		2018					2019		2018
Gas distribution operations (mmBtu in millions)
Firm	99		119		(16.8	)%		396		434		(8.8	)%
Interruptible	22		25		(12.0	)%		46		49		(6.1	)%
Total(*)	121		144		(16.0	)%		442		483		(8.5	)%
Wholesale gas services (mmBtu in millions/day)
Daily physical sales	5.7		6.4		(10.9	)%		6.3		6.6		(4.5	)%
Gas marketing services (mmBtu in millions)
Firm:
Georgia	4		5		(20.0	)%		19		22		(13.6	)%
Illinois	2		2		—			8		8		—
Ohio	1		2		(50.0	)%		8		11		(27.3	)%
Other	1		1		—			2		2		—
Interruptible large commercial and industrial	3		3		—			7		7		—
Total	11		13		(15.4	)%		44		50		(12.0	)%

(*)

Includes total volumes of natural gas sold of 12 mmBtu and 38 mmBtu for the three and six months ended June 30, 2018 related to Elizabethtown Gas, Elkton Gas, and Florida City Gas, which were sold in July 2018. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company Gas – Sale of Elizabethtown Gas and Elkton Gas" and " – Sale of Florida City Gas" for additional information.

Cost of Other Sales

Second Quarter 2019 vs. Second Quarter 2018				Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)		(% change)		(change in millions)		(% change)
$(5)		(100.0)		$(12)		(100.0)

Cost of other sales related to Pivotal Home Solutions, which was sold in June 2018. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company Gas – Sale of Pivotal Home Solutions" for additional information.

Other Operations and Maintenance Expenses

Second Quarter 2019 vs. Second Quarter 2018				Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)		(% change)		(change in millions)		(% change)
$(39)		(16.4)		$(81)		(15.8)

In the second quarter 2019, other operations and maintenance expenses were $199 million compared to $238 million for the corresponding period in 2018. Excluding a $34 million decrease related to the Southern Company Gas Dispositions, other operations and maintenance expenses decreased $5 million. This decrease was primarily due to disposition-related costs incurred during 2018 and decreased compensation and benefit costs, partially offset by an increase in expenses associated with pipeline compliance and maintenance activities.

For year-to-date 2019, other operations and maintenance expenses were $433 million compared to $514 million for the corresponding period in 2018. Excluding a $63 million decrease related to the Southern Company Gas Dispositions, other operations and maintenance expenses decreased $18 million. This decrease was primarily due to

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a one-time adjustment in 2018 for the adoption of a new paid time off policy, disposition-related costs incurred during 2018, and decreased compensation and benefits costs, partially offset by an increase in expenses associated with pipeline compliance and maintenance activities. 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.

Depreciation and Amortization

Second Quarter 2019 vs. Second Quarter 2018				Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)		(% change)		(change in millions)		(% change)
$(7)		(5.6)		$(17)		(6.7)

In the second quarter 2019, depreciation and amortization was $119 million compared to $126 million for the corresponding period in 2018. Excluding a $10 million decrease related to the Southern Company Gas Dispositions, depreciation and amortization increased $3 million. This increase was primarily due to continued infrastructure investments at gas distribution operations.

For year-to-date 2019, depreciation and amortization was $238 million compared to $255 million for the corresponding period in 2018. Excluding a $26 million decrease related to the Southern Company Gas Dispositions, depreciation and amortization increased $9 million. This increase was primarily due to continued infrastructure investments at gas distribution operations.

Taxes Other Than Income Taxes

Second Quarter 2019 vs. Second Quarter 2018				Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)		(% change)		(change in millions)		(% change)
$(2)		(4.2)		$3		2.4

In the second quarter 2019, taxes other than income taxes were $46 million compared to $48 million for the corresponding period in 2018. Excluding a $2 million decrease related to the Southern Company Gas Dispositions, taxes other than income taxes remained unchanged.

For year-to-date 2019, taxes other than income taxes were $128 million compared to $125 million for the corresponding period in 2018. Excluding a $6 million decrease related to the Southern Company Gas Dispositions, taxes other than income taxes increased $9 million. This increase primarily reflects increases in Nicor Gas' invested capital tax as a result of increased infrastructure investments and increased revenue tax expenses as a result of higher natural gas revenues at Nicor Gas, both of which are passed through to customers.

Goodwill Impairment

Second Quarter 2019 vs. Second Quarter 2018				Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)		(% change)		(change in millions)		(% change)
$—		N/M		$(42)		N/M

N/M - Not meaningful

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 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company Gas – Sale of Pivotal Home Solutions" for additional information.

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Loss on Disposition

Second Quarter 2019 vs. Second Quarter 2018				Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)		(% change)		(change in millions)		(% change)
$(36)		N/M		$(36)		N/M

N/M - Not meaningful

As a result of the sale of Pivotal Home Solutions in June 2018, a $36 million pre-tax loss was recorded in the second quarter 2018. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company Gas – Sale of Pivotal Home Solutions" for additional information.

Earnings from Equity Method Investments

Second Quarter 2019 vs. Second Quarter 2018				Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)		(% change)		(change in millions)		(% change)
$—		—		$6		8.1

In the second quarter 2019 and 2018, earnings from equity method investments were $31 million. For year-to-date 2019, earnings from equity method investments were $80 million compared to $74 million for the corresponding period in 2018. For both the second quarter and year-to-date 2019, earnings from equity method investments reflect higher earnings from SNG as a result of rate increases implemented by SNG that became effective September 2018, partially offset by a $6 million pre-tax loss on the sale of Triton in May 2019. See Note (E) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.

Other Income (Expense), Net

Second Quarter 2019 vs. Second Quarter 2018				Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)		(% change)		(change in millions)		(% change)
$3		100.0		$(5)		(33.3)

For year-to-date 2019, other income (expense), net was $10 million compared to $15 million for the corresponding period in 2018. This decrease was primarily due to a contractor litigation settlement in the first quarter 2018. See Note 2 to the financial statements under "Southern Company Gas – Infrastructure Replacement Programs and Capital Projects – Atlanta Gas Light – PRP" in Item 8 of the Form 10-K for additional information.

Income Taxes

Second Quarter 2019 vs. Second Quarter 2018				Year-to-Date 2019 vs. Year-to-Date 2018
(change in millions)		(% change)		(change in millions)		(% change)
$(49)		(89.1)		$(76)		(47.8)

In the second quarter 2019, income taxes were $6 million compared to $55 million for the corresponding period in 2018. Excluding a $38 million decrease related to the Southern Company Gas Dispositions, income taxes decreased $11 million. The decrease was primarily due to an increase in the flowback of excess deferred income taxes in 2019 primarily at Atlanta Gas Light as previously authorized by the Georgia PSC and the reversal of a $13 million federal income tax valuation allowance in connection with the sale of Triton in May 2019, partially offset by higher pre-tax earnings.

For year-to-date 2019, income taxes were $83 million compared to $159 million for the corresponding period in 2018. Excluding a $51 million decrease related to the Southern Company Gas Dispositions, income taxes decreased $25 million. This decrease was primarily due to an increase in the flowback of excess deferred income taxes in 2019 primarily at Atlanta Gas Light as previously authorized by the Georgia PSC and the reversal of a $13 million federal income tax valuation allowance in connection with the sale of Triton in May 2019.

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See Note (E) to the Condensed Financial Statements herein for additional information on the sale of Triton and Note 2 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information on the Atlanta Gas Light stipulation reflecting the impacts of the Tax Reform Legislation. Also see Note (G) to the Condensed Financial Statements 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 base rate changes, infrastructure replacement programs and capital projects, and 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 pipeline investments, wholesale gas services, and gas marketing services allows it to focus on a direct measure of performance 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.

	Second Quarter 2019			Second Quarter 2018				Year-to-Date 2019			Year-to-Date 2018
	(in millions)
Operating Income	$	134		$	49			$	487		$	436
Other operating expenses(a)	364			448				799			972
Revenue taxes(b)	(22		)	(23		)		(76		)	(73		)
Adjusted Operating Margin	$	476		$	474			$	1,210		$	1,335

(a)	Includes other operations and maintenance expenses, 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.

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Segment Information

Adjusted operating margin, operating expenses, and net income for each segment are provided in the table below. See Note (M) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.

	Second Quarter 2019												Second Quarter 2018
	Adjusted Operating Margin(a)				Operating Expenses(a)				Net Income (Loss)				Adjusted Operating Margin(a)(b)				Operating Expenses(a)(b)				Net Income (Loss)(b)
	(in millions)												(in millions)
Gas distribution operations	$	394			$	287			$	58			$	429			$	296			$	68
Gas pipeline investments	8				3				25				8				3				21
Wholesale gas services	41				10				23				(16		)		14				(21		)
Gas marketing services	27				31				(3		)		48				87				(76		)
All other	7				12				3				6				26				(23		)
Intercompany eliminations	(1		)		(1		)		—				(1		)		(1		)		—
Consolidated	$	476			$	342			$	106			$	474			$	425			$	(31	)

(a)	Adjusted operating margin and operating expenses are adjusted for Nicor Gas' revenue tax expenses, which are passed through directly to customers.

(b)	2018 adjusted operating margin, operating expenses, and net income for gas distribution operations and gas marketing services include the impacts of the Southern Company Gas Dispositions. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company Gas" for additional information.

	Year-to-Date 2019												Year-to-Date 2018
	Adjusted Operating Margin(a)				Operating Expenses(a)				Net Income (Loss)				Adjusted Operating Margin(a)(b)				Operating Expenses(a)(b)				Net Income (Loss)(b)
	(in millions)												(in millions)
Gas distribution operations	$	918			$	601			$	191			$	986			$	620			$	216
Gas pipeline investments	16				6				57				16				6				48
Wholesale gas services	125				29				70				147				36				83
Gas marketing services	142				62				58				175				181				(63		)
All other	13				29				—				15				60				(36		)
Intercompany eliminations	(4		)		(4		)		—				(4		)		(4		)		—
Consolidated	$	1,210			$	723			$	376			$	1,335			$	899			$	248

(a)	Adjusted operating margin and operating expenses are adjusted for Nicor Gas' revenue tax expenses, which are passed through directly to customers.

(b)	2018 adjusted operating margin, operating expenses, and net income for gas distribution operations and gas marketing services include the impacts of the Southern Company Gas Dispositions. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company Gas" 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, operations and 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

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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.

In July 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. Also in July 2018, Southern Company Gas and its wholly-owned direct subsidiary, NUI Corporation, completed the sale of Pivotal Utility Holdings, which primarily consisted of Florida City Gas, to NextEra Energy. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company Gas" for additional information.

Excluding the impact of the utilities sold in 2018, the second quarter and year-to-date 2019 results of gas distribution operations are as follows:

	Second Quarter 2019										Year-to-Date 2019
Favorable (Unfavorable)	Variance to Prior Period			Impact of Utilities Sold in 2018			Variance Excluding Utilities Sold in 2018				Variance to Prior Period			Impact of Utilities Sold in 2018			Variance Excluding Utilities Sold in 2018
	(in millions)										(in millions)
Adjusted Operating Margin	$	(35	)	$	45		$	10			$	(68	)	$	133		$	65
Operating expenses	9			(35		)	(26		)		19			(75		)	(56		)
Other income (expense), net	—			—			—				(7		)	—			(7		)
Interest expense	(3		)	(6		)	(9		)		(4		)	(13		)	(17		)
Income tax expense	19			(1		)	18				35			(12		)	23
Net Income	$	(10	)	$	3		$	(7	)		$	(25	)	$	33		$	8

Second Quarter 2019 vs. Second Quarter 2018

In the second quarter 2019, net income decreased $7 million, or 10.8%, compared to the corresponding period in 2018. The $10 million increase in adjusted operating margin primarily reflects additional revenue from continued investments recovered through infrastructure replacement programs, partially offset by warmer weather in Illinois during the second quarter 2019 compared to the corresponding period in 2018. The $26 million increase in operating expenses includes increased compensation and benefit costs, higher expenses passed through directly to customers, increased expenses for pipeline compliance and maintenance activities, and additional depreciation primarily due to additional assets placed in service. The $9 million increase in interest expense results from the issuance of first mortgage bonds at Nicor Gas in the prior year. Income tax expense decreased $18 million primarily due to an increase in the flowback of excess deferred income taxes at Atlanta Gas Light in 2019 and lower pre-tax earnings.

Year-to-Date 2019 vs. Year-to-Date 2018

For year-to-date 2019, net income increased $8 million, or 4.4%, compared to the corresponding period in 2018. The $65 million increase in adjusted operating margin primarily reflects additional revenue from continued investments recovered through infrastructure replacement programs and base rate increases, the effect of revenues deferred in 2018 as a result of the Tax Reform Legislation, and colder weather in Illinois during the first quarter 2019 compared to the corresponding period in 2018. The $56 million increase in operating expenses includes increased compensation and benefit costs, higher expenses passed through directly to customers, increased expenses for pipeline compliance and maintenance activities, and additional depreciation primarily due to additional assets placed in service. The decrease in other income (expense), net is primarily due to a contractor litigation settlement in the first quarter 2018. The $17 million increase in interest expense is primarily from the issuance of first mortgage bonds at Nicor Gas in the prior year. The $23 million decrease in income tax expense is primarily due to

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an increase in the flowback of excess deferred income taxes in 2019, primarily at Atlanta Gas Light and lower pre-tax earnings.

See Note 2 to the financial statements under "Southern Company Gas – Rate Proceedings – Atlanta Gas Light" and " – Infrastructure Replacement Programs and Capital Projects – Atlanta Gas Light – PRP" in Item 8 of the Form 10-K for additional information on Atlanta Gas Light's stipulation reflecting the impacts of the Tax Reform Legislation and the contractor litigation settlement, respectively.

Gas Pipeline Investments

Gas pipeline investments consists primarily of joint ventures in natural gas pipeline investments including SNG, Atlantic Coast Pipeline, PennEast Pipeline, and a 50% joint ownership interest in the Dalton Pipeline. See Note (E) to the Condensed Financial Statements herein and Note 7 to the financial statements in Item 8 of the Form 10-K for additional information.

In the second quarter and year-to-date 2019, net income increased $4 million, or 19.0%, and $9 million, or 18.8%, respectively, compared to the corresponding periods in 2018. These increases primarily relate to higher earnings from SNG.

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.

In the second quarter 2019, net income increased $44 million, or 209.5%, compared to the corresponding period in 2018. This increase primarily relates to a $57 million increase in adjusted operating margin and a $4 million decrease in operating expenses, partially offset by an increase of $18 million in income tax expense due to higher pre-tax earnings. For year-to-date 2019, net income decreased $13 million, or 15.7%, compared to the corresponding period in 2018. This decrease primarily relates to a $22 million decrease in adjusted operating margin, partially offset by a $7 million decrease in operating expenses.

Details of the changes in adjusted operating margin are provided in the table below. The decreases in operating expenses primarily reflect lower compensation and benefit expenses.

	Second Quarter 2019			Second Quarter 2018				Year-to-Date 2019			Year-to-Date 2018
	(in millions)
Commercial activity recognized	$	(1	)	$	17			$	37		$	189
Gain on storage derivatives	2			—				5			1
Gain (loss) on transportation and forward commodity derivatives	48			(28		)		77			(44		)
LOCOM adjustments, net of current period recoveries	(6		)	—				(8		)	(3		)
Purchase accounting adjustments to fair value inventory and contracts	(2		)	(5		)		14			4
Adjusted operating margin	$	41		$	(16	)		$	125		$	147

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Change in Commercial Activity

The commercial activity at wholesale gas services includes recognition of storage and transportation values that were generated in prior periods, which reflect the impact of prior period hedge gains and losses as associated physical transactions occur. The decrease in commercial activity in the second quarter and year-to-date 2019 compared to the corresponding period in 2018 was primarily due to significant natural gas price volatility that resulted from prolonged cold weather during the first quarter 2018 coupled with low 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 2019 resulted in storage derivative gains. Transportation and forward commodity derivative gains in 2019 are primarily the result of narrowing transportation spreads due to supply constraints and increases in natural gas supply, which impacted forward prices at natural gas receipt and delivery points, primarily in the Northeast and Midwest regions.

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, 2019. 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 losses(c)
	(in mmBtu in millions)			(in millions)				(in millions)
2019	16			$	2			$	(15	)
2020 and thereafter	18			8				(62		)
Total at June 30, 2019	34			$	10			$	(77	)

(a)	At June 30, 2019, the WACOG of wholesale gas services' expected natural gas withdrawals from storage was $2.05 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 transportation derivative gains and (losses) that will be settled during the period and the physical transportation transactions that offset the derivative gains and losses 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.

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Gas Marketing Services

Gas marketing services provides energy-related products and services to natural gas markets and participants in customer choice programs that were approved in various states to increase competition. These programs allow customers to choose their natural gas supplier while the local distribution utility continues to provide distribution and transportation services. 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 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company Gas" for additional information.

Second Quarter 2019 vs. Second Quarter 2018

In the second quarter 2019, net loss decreased $73 million compared to the corresponding period in 2018. This decrease primarily relates to a $56 million decrease in operating expenses and a $36 million decrease in income tax expense, partially offset by a $21 million decrease in adjusted operating margin. The decrease in net loss is primarily attributable to the 2018 disposition of Pivotal Home Solutions.

Year-to-Date 2019 vs. Year-to-Date 2018

For year-to-date 2019, net income increased $121 million compared to the corresponding period in 2018. This increase primarily relates to a $119 million decrease in operating expenses and a $33 million decrease in income tax expense, partially offset by a $33 million decrease in adjusted operating margin.

Excluding a $43 million decrease attributable to the 2018 disposition of Pivotal Home Solutions, adjusted operating margin increased $10 million, which primarily reflects favorable margins and recovery of prior period hedge losses. Excluding a $118 million decrease attributable to the 2018 disposition of Pivotal Home Solutions that includes the related goodwill impairment charge, operating expense decreased $1 million.

All Other

All other includes Southern Company Gas' storage and fuels operations and its investment in Triton through completion of its sale on May 29, 2019, 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 2019 vs. Second Quarter 2018

In the second quarter 2019, net income increased $26 million compared to the corresponding period in 2018. This increase primarily reflects a $14 million decrease in operating expenses and a $13 million decrease in income taxes. The decrease in operating expenses was primarily due to disposition-related costs incurred during 2018. The decrease in income taxes reflects lower taxes due to the reversal of a federal income tax valuation allowance in connection with the sale of Triton.

Year-to-Date 2019 vs. Year-to-Date 2018

For year-to-date 2019, net income increased $36 million compared to the corresponding period in 2018. This increase primarily reflects a $31 million decrease in operating expenses and a $10 million decrease in income taxes, partially offset by a $2 million decrease in adjusted operating margin. The decrease in operating expenses primarily reflects a one-time adjustment in the first quarter 2018 for the adoption of a new paid time off policy, disposition-related costs incurred during 2018, and a decrease in depreciation and amortization. The decrease in income taxes reflects lower taxes due to the reversal of a federal income tax valuation allowance in connection with the sale of Triton.

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Segment Reconciliations

Reconciliations of operating income to adjusted operating margin for the second quarter and year-to-date 2019 and 2018 are reflected in the following tables. See Note (M) to the Condensed Financial Statements herein for additional information.

	Second Quarter 2019
	Gas Distribution Operations			Gas Pipeline Investments			Wholesale Gas Services			Gas Marketing Services			All Other			Intercompany Elimination			Consolidated
	(in millions)
Operating Income (Loss)	$	107		$	5		$	31		$	(4	)	$	(5	)	$	—		$	134
Other operating expenses(a)	309			3			10			31			12			(1		)	364
Revenue tax expense(b)	(22		)	—			—			—			—			—			(22		)
Adjusted Operating Margin	$	394		$	8		$	41		$	27		$	7		$	(1	)	$	476

	Second Quarter 2018
	Gas Distribution Operations			Gas Pipeline Investments			Wholesale Gas Services			Gas Marketing Services			All Other			Intercompany Elimination			Consolidated
	(in millions)
Operating Income (Loss)	$	133		$	5		$	(30	)	$	(39	)	$	(20	)	$	—		$	49
Other operating expenses(a)	319			3			14			87			26			(1		)	448
Revenue tax expense(b)	(23		)	—			—			—			—			—			(23		)
Adjusted Operating Margin	$	429		$	8		$	(16	)	$	48		$	6		$	(1	)	$	474

	Year-to-Date 2019
	Gas Distribution Operations			Gas Pipeline Investments			Wholesale Gas Services			Gas Marketing Services			All Other			Intercompany Elimination			Consolidated
	(in millions)
Operating Income (Loss)	$	317		$	10		$	96		$	80		$	(16	)	$	—		$	487
Other operating expenses(a)	677			6			29			62			29			(4		)	799
Revenue tax expense(b)	(76		)	—			—			—			—			—			(76		)
Adjusted Operating Margin	$	918		$	16		$	125		$	142		$	13		$	(4	)	$	1,210

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	Year-to-Date 2018
	Gas Distribution Operations			Gas Pipeline Investments			Wholesale Gas Services			Gas Marketing Services			All Other			Intercompany Elimination			Consolidated
	(in millions)
Operating Income (Loss)	$	366		$	10		$	111		$	(6	)	$	(45	)	$	—		$	436
Other operating expenses(a)	693			6			36			181			60			(4		)	972
Revenue tax expense(b)	(73		)	—			—			—			—			—			(73		)
Adjusted Operating Margin	$	986		$	16		$	147		$	175		$	15		$	(4	)	$	1,335

(a)	Includes other operations and maintenance expenses, 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 Southern Company Gas Dispositions are expected to materially decrease future earnings and cash flows to Southern Company Gas. In the second quarter and year-to-date 2018, net income attributable to these dispositions, excluding the related goodwill impairment and loss on disposition, was $38 million and $3 million, respectively. 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 pipeline investments, wholesale gas services, and gas marketing services sectors. These factors include Southern Company Gas' ability to maintain constructive regulatory environments that allow 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. 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, its 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. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters" of Southern Company Gas in Item 7 of the Form 10-K for additional information on permitting challenges experienced by the Atlantic Coast Pipeline. 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.

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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 second quarter and year-to-date 2019 results are not necessarily indicative of the results to be expected for any other period.

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/or 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 (C) to the Condensed Financial Statements under "Environmental Remediation" 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 under "Environmental Remediation" in Item 8 of the Form 10-K for additional information.

Regulatory Matters

See Note 2 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information regarding Southern Company Gas' regulatory matters.

Rate Proceedings

Nicor Gas

In November 2018, Nicor Gas filed a general base rate case with the Illinois Commission requesting a $230 million increase in annual base rate revenues. The requested increase is based on a projected test year for the 12-month period ending September 30, 2020, a ROE of 10.6%, and an increase in the equity ratio from 52% to 54% to address the negative cash flow and credit metric impacts of the Tax Reform Legislation.

On April 16, 2019, Nicor Gas entered into a stipulation agreement to resolve all related issues with the Staff of the Illinois Commission, including a ROE of 9.86% and an equity ratio of 54%. Also on April 16, 2019, Nicor Gas filed its rebuttal testimony with the Illinois Commission incorporating the stipulation agreement and addressing the remaining items outstanding with the other two intervenors. As a result of the stipulation agreement and rebuttal testimony, the revised requested annual revenue increase is $180 million.

The Illinois Commission is expected to rule on the requested increase by early October 2019, after which rate adjustments will be effective. The ultimate outcome of this matter cannot be determined at this time.

Atlanta Gas Light

On June 3, 2019, Atlanta Gas Light filed a general base rate case with the Georgia PSC requesting a $96 million increase in annual base rate revenues. The requested increase is based on a forward-looking test year for the 12-month period ending July 31, 2020, a ROE of 10.75% with an earnings band based on a ROE between 10.55% and 10.95%, and a continued equity ratio of 55%. The filing also requests the continuation of the Georgia rate adjustment mechanism, as previously authorized. Atlanta Gas Light expects the Georgia PSC to issue a final order on this matter on December 19, 2019 with the new rates becoming effective January 1, 2020. The ultimate outcome of this matter cannot be determined at this time.

Virginia Natural Gas

In December 2018, the Virginia Commission approved Virginia Natural Gas' annual information form filing, which reduced annual base rates by $14 million effective January 1, 2019 due to lower tax expense as a result of the Tax Reform Legislation. This approval also required Virginia Natural Gas to issue customer refunds, via bill credits, for

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$14 million related to 2018 tax benefits deferred as a regulatory liability, current, on the balance sheet at December 31, 2018. These customer refunds were completed in the first quarter 2019.

Regulatory Infrastructure Programs

In addition to capital expenditures recovered through base rates by each of the natural gas distribution utilities, Nicor Gas and Virginia Natural Gas have separate rate riders that provide for timely recovery of capital expenditures for specific infrastructure replacement programs. Infrastructure expenditures incurred under these programs in the first six months of 2019 were as follows:

Utility	Program	Year-to-Date 2019
		(in millions)
Nicor Gas	Investing in Illinois	$	107
Virginia Natural Gas	Steps to Advance Virginia's Energy (SAVE)	21
Total		$	128

On April 8, 2019, Virginia Natural Gas filed an application with the Virginia Commission to amend and extend its SAVE program. The proposal would allow Virginia Natural Gas to continue replacing aging pipeline infrastructure and increase its authorized investment under the currently-approved plan. Virginia Natural Gas seeks to amend its currently-approved plan by increasing the authorized investment in 2019 from $35 million to $40 million and to extend the plan for an additional five years until 2024, with proposed annual investments of $50 million in 2020, $60 million in 2021, and $70 million in each year from 2022 through 2024, for a maximum total investment over the six-year term (2019 through 2024) of $370 million. The proposed investment schedule would also allow for variances of up to $6 million in 2019, $8 million in 2020, $9 million in 2021, and $10 million in each year from 2022 through 2024, with a total potential net variance of up to $10 million allowed for the program. The Virginia Commission is expected to rule on the request in the fourth quarter 2019. The ultimate outcome of this matter cannot be determined at this time.

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 2 to the financial statements under "Southern Company Gas – Infrastructure Replacement Programs and Capital Projects" in Item 8 of the Form 10-K for additional information.

Affiliate Asset Management Agreements

On March 15, 2019, the Virginia Commission approved an extension of Virginia Natural Gas' asset management agreement with Sequent to March 31, 2021. Southern Company Gas does not expect this new agreement to have a material impact on its financial statements.

FERC Matters

See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "FERC Matters" of Southern Company Gas in Item 7 of the Form 10-K and Notes 7 and 9 to the financial statements under "Southern Company Gas – Equity Method Investments" and "Guarantees," respectively, in Item 8 of the Form 10-K for additional information regarding Southern Company Gas' gas pipeline construction projects.

Other Matters

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

Southern Company Gas is involved in various other matters that could affect future earnings, including matters being litigated, as well as other regulatory matters and matters that could result in asset impairments. In addition, Southern Company Gas is subject to certain claims and legal actions arising in the ordinary course of business. The

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ultimate outcome of such pending or potential litigation, regulatory matters, or potential asset impairments cannot be determined at this time; however, for current proceedings not specifically reported in Notes (B) and (C) 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 Notes (B) and (C) to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.

See Note 3 to the financial statements in Item 8 of the Form 10-K under "Other Matters – Southern Company Gas" for information on a natural gas storage facility consisting of two salt dome caverns in Louisiana. The future performance of this facility, as well as Southern Company Gas' two other natural gas storage facilities located in California and Texas, could be impacted by ongoing changes in the U.S. natural gas storage market. Recent sales of natural gas storage facilities have resulted in losses for the sellers and may imply an impact on future rates and/or asset values. Southern Company Gas is evaluating these recent market transactions for impacts on its plans to return one of the salt dome caverns in Louisiana back to service in 2021. Sustained diminished natural gas storage values could trigger impairment of one or all of these natural gas storage facilities, which have a combined net book value of $438 million at June 30, 2019. The ultimate outcome of these matters cannot be determined at this time, but could have a material impact on Southern Company Gas' financial statements.

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 Notes 1, 5, and 6 to the financial statements 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 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, 2019. 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. At June 30, 2019, the amount of subsidiary retained earnings restricted to dividend totaled $888 million. This restriction did not impact Southern Company Gas' ability to meet its cash obligations.

Net cash provided from operating activities totaled $931 million for the first six months of 2019, a decrease of $387 million from the corresponding period in 2018. The decrease was primarily due to the impacts of the Southern Company Gas Dispositions and the timing of vendor payments, partially offset by the timing of collection of customer receivables. Net cash used for investing activities totaled $586 million for the first six months of 2019

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primarily due to gross property additions related to utility capital expenditures and infrastructure investments recovered through replacement programs at gas distribution operations and capital contributed to equity method pipeline investments, partially offset by proceeds from the sale of Triton. Net cash used for financing activities totaled $355 million for the first six months of 2019 primarily due to repayments of commercial paper borrowings 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 2019 include a decrease of $256 million in natural gas for sale due to the use of stored natural gas and a $158 million decrease in notes payable primarily related to net repayments of commercial paper borrowings. Other significant balance sheet changes include decreases of $440 million and $463 million in energy marketing receivables and payables, respectively, due to lower natural gas prices and volumes of natural gas sold, and an increase of $429 million in total property, plant, and equipment primarily due to utility capital expenditures and infrastructure investments recovered through replacement programs. Balance sheet changes for the first six months of 2019 also include recording $95 million in operating lease right-of use assets and $94 million in operating lease obligations related to the adoption of ASU No. 2016-02, Leases (Topic 842) (ASC 842). See Note (L) to the Condensed Financial Statements herein for additional information on the adoption of ASC 842.

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. Subsequent to June 30, 2019, Nicor Gas repaid at maturity $50 million aggregate principal amount of first mortgage bonds due July 30, 2019. An additional $300 million will be required through June 30, 2020 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 2 to the financial statements under "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 from sources similar to those used in the past, which were primarily from operating cash flows, external securities issuances, borrowings from financial institutions, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, depend upon prevailing market conditions, regulatory approval, and other factors. 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.

Subsequent to June 30, 2019, Southern Company Gas received a $400 million capital contribution from Southern Company.

Southern Company Gas' current liabilities exceeded current assets by $682 million primarily as a result of $492 million in notes payable and $351 million in securities due within one year. 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.

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At June 30, 2019, Southern Company Gas had $56 million of cash and cash equivalents. Committed credit arrangements with banks at June 30, 2019 were as follows:

Company	Expires 2024				Unused
	(in millions)
Southern Company Gas Capital(a)	$	1,250			$	1,245
Nicor Gas	500				500
Total(b)	$	1,750			$	1,745

(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 8 to the consolidated financial statements 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.

In May 2019, Southern Company Gas Capital, along with Nicor Gas, amended and restated its multi-year credit arrangement to extend the maturity date to 2024 and decrease the aggregate borrowing capacity from $1.9 billion to $1.75 billion.

The multi-year credit arrangement of Southern Company Gas Capital and Nicor Gas (Facility) contains a covenant that limits the debt levels 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, 2019, 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 has substantial cash flow from operating activities and access to capital markets, including the commercial paper programs, and financial institutions to meet liquidity needs. 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. 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, 2019							Short-Term Debt During the Period(*)
	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	$	372			2.6	%		$	297			2.7	%		$	436
Nicor Gas	120				2.6			27				2.6			120
Total	$	492			2.6	%		$	324			2.7	%

(*)	Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 2019.

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

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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 natural gas purchases and sales, fuel transportation and storage, and energy price risk management. The maximum potential collateral requirement under these contracts at June 30, 2019 was approximately $13 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 its regulated subsidiaries have taken 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 2 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Southern Company Gas" herein for information on additional requests for increased equity ratios included in rate case proceedings for Nicor Gas and Atlanta Gas Light expected to conclude later in 2019.

Financing Activities

The long-term debt on Southern Company Gas' balance sheets includes both principal and non-principal components. As of June 30, 2019, the non-principal components totaled $432 million, which consisted of the unamortized portions of the fair value adjustment recorded in purchase accounting, debt premiums, debt discounts, and debt issuance costs.

Southern Company Gas did not issue or redeem any securities during the six months ended June 30, 2019.

Subsequent to June 30, 2019, Nicor Gas repaid at maturity $50 million aggregate principal amount of 4.7% first mortgage bonds due July 30, 2019.

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 quarter 2019. 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 (I) and (J) 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 may 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

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SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 2019			Second Quarter 2018				Year-to-Date 2019			Year-to-Date 2018
	(in millions)
Contracts outstanding at beginning of period, assets (liabilities), net	$	(128	)	$	(70	)		$	(167	)	$	(106	)
Contracts realized or otherwise settled	5			2				—			51
Current period changes(a)	33			(22		)		77			(35		)
Contracts outstanding at the end of period, assets (liabilities), net	$	(90	)	$	(90	)		$	(90	)	$	(90	)
Netting of cash collateral	178			183				178			183
Cash collateral and net fair value of contracts outstanding at end of period(b)	$	88		$	93			$	88		$	93

(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 $0 million and $3 million at June 30, 2019 and 2018, respectively.

The maturities of Southern Company Gas' energy-related derivative contracts at June 30, 2019 were as follows:

					Fair Value Measurements
					June 30, 2019
	Total Fair Value				Maturity
					Year 1				Years 2 & 3				Years 4 and thereafter
	(in millions)
Level 1(a)	$	(135	)		$	(46	)		$	(62	)		$	(27	)
Level 2(b)	55				27				25				3
Level 3(c)	(10		)		1				—				(11		)
Fair value of contracts outstanding at end of period(d)	$	(90	)		$	(18	)		$	(37	)		$	(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)	Valued using a combination of observable and unobservable inputs.

(d)	Excludes cash collateral of $178 million as well as premium and associated intrinsic value associated with weather derivatives of $0 million at June 30, 2019.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS

FOR

THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

ALABAMA POWER COMPANY

GEORGIA 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	161
B	Regulatory Matters	166
C	Contingencies	174
D	Revenue from Contracts with Customers	179
E	Consolidated Entities and Equity Method Investments	187
F	Financing	188
G	Income Taxes	193
H	Retirement Benefits	194
I	Fair Value Measurements	199
J	Derivatives	204
K	Acquisitions and Dispositions	216
L	Leases	219
M	Segment and Related Information	226

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, M
Alabama Power	A, B, C, D, F, G, H, I, J, L
Georgia Power	A, B, C, D, F, G, H, I, J, L
Mississippi Power	A, B, C, D, F, G, H, I, J, L
Southern Power	A, C, D, E, F, G, H, I, J, K, L
Southern Company Gas	A, B, C, D, E, F, G, H, I, J, K, L, M

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES

ALABAMA POWER COMPANY

GEORGIA 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, 2018 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, 2019 and 2018. 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

In 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged and there is no change to the accounting for existing leveraged leases. The registrants adopted the new standard effective January 1, 2019. See Note (L) for additional information and related disclosures.

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(UNAUDITED)

Goodwill and Other Intangible Assets

Goodwill at June 30, 2019 and December 31, 2018 was as follows:

	At June 30, 2019			At December 31, 2018
	(in millions)
Southern Company	$	5,282		$	5,315
Southern Company Gas:
Gas distribution operations	$	4,034		$	4,034
Gas marketing services	981			981
Southern Company Gas total	$	5,015		$	5,015

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. A goodwill impairment charge of $32 million was recorded in the second quarter 2019 in contemplation of the July 22, 2019 sale of one of PowerSecure's business units. See Note (K) under "Southern Company" for additional information.

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(UNAUDITED)

Other intangible assets were as follows:

	At June 30, 2019										At December 31, 2018
	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	$	211		$	(105	)	$	106			$	223		$	(94	)	$	129
Trade names	70			(23		)	47				70			(21		)	49
Storage and transportation contracts	64			(58		)	6				64			(54		)	10
PPA fair value adjustments	371			(60		)	311				405			(61		)	344
Other	12			(7		)	5				11			(5		)	6
Total other intangible assets subject to amortization	$	728		$	(253	)	$	475			$	773		$	(235	)	$	538
Other intangible assets not subject to amortization:
Federal Communications Commission licenses	75			—			75				75			—			75
Total other intangible assets	$	803		$	(253	)	$	550			$	848		$	(235	)	$	613
Southern Power
Other intangible assets subject to amortization:
PPA fair value adjustments	$	371		$	(60	)	$	311			$	405		$	(61	)	$	344
Southern Company Gas
Other intangible assets subject to amortization:
Gas marketing services
Customer relationships	$	156		$	(95	)	$	61			$	156		$	(84	)	$	72
Trade names	26			(8		)	18				26			(7		)	19
Wholesale gas services
Storage and transportation contracts	64			(58		)	6				64			(54		)	10
Total other intangible assets subject to amortization	$	246		$	(161	)	$	85			$	246		$	(145	)	$	101

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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, 2019
	(in millions)
Southern Company	$	15		$	32
Southern Power(a)	$	4		$	10
Southern Company Gas
Gas marketing services(b)	$	6		$	12
Wholesale gas services(a)	2			4
Southern Company Gas total	$	8		$	16

(a)	Recorded as a reduction to operating revenues.

(b)	Included in depreciation and amortization.

Restricted Cash

At December 31, 2018, Georgia Power had restricted cash related to the redemption of pollution control revenue bonds, which were redeemed in January 2019. See Note (F) under "Financing Activities" for additional information. At both June 30, 2019 and December 31, 2018, 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, 2019 and/or December 31, 2018:

	Southern Company				Southern Company Gas
	(in millions)
At June 30, 2019
Cash and cash equivalents	$	1,383			$	56
Restricted cash:
Other accounts and notes receivable	4				4
Total cash, cash equivalents, and restricted cash	$	1,386		(*)	$	60

(*)	Total does not add due to rounding.

	Southern Company			Georgia Power			Southern Company Gas
	(in millions)
At December 31, 2018
Cash and cash equivalents	$	1,396		$	4		$	64
Cash and cash equivalents held for sale	9			—			—
Restricted cash:
Restricted cash	—			108			—
Other accounts and notes receivable	114			—			6
Total cash, cash equivalents, and restricted cash	$	1,519		$	112		$	70

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Natural Gas for Sale

Southern Company Gas, with the exception of Nicor Gas, carries natural gas inventory 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 recorded adjustments of $7 million and $10 million for the three and six months ended June 30, 2019, respectively, and no material adjustments for the comparable periods in 2018.

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. Nicor Gas had no inventory decrement at June 30, 2019.

Asset Retirement Obligations

See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information regarding AROs.

Details of the AROs included in the condensed balance sheets of Southern Company, Alabama Power, and Mississippi Power at June 30, 2019 are shown in the following table. There were no material changes in the AROs of Georgia Power or Southern Power during the first six months of 2019.

	Southern Company			Alabama Power			Mississippi Power
	(in millions)
Balance at December 31, 2018	$	9,394		$	3,210		$	160
Liabilities incurred	6			—			—
Liabilities settled	(142		)	(43		)	(17		)
Accretion	197			70			2
Cash flow revisions	452			308			59
Balance at June 30, 2019	$	9,907		$	3,545		$	204

In June 2019, Alabama Power recorded an increase of approximately $308 million to its AROs primarily related to the CCR Rule and the related state rule based on management's completion of closure designs during the second quarter 2019 for all but two of its ash pond facilities. Mississippi Power also recorded an increase of approximately $58 million to its AROs related to the CCR Rule, primarily associated with the ash pond facility at Plant Greene County, which is jointly owned with Alabama Power. The additional estimated costs to close these ash ponds under the planned closure-in-place methodology primarily relate to cost inputs from contractor bids, internal drainage and dewatering system designs, and increases in the estimated ash volumes. The cost estimate for the remaining Alabama Power ash pond facilities will be updated within the next 12 months and the change could be material.

As further analysis is performed and additional details are developed with respect to ash pond closures, the traditional electric operating companies expect to periodically update their ARO cost estimates. Additionally, the closure designs and plans in the States of Alabama and Georgia are subject to approval by environmental regulatory agencies. 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 these matters cannot be determined at this time.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

(B) REGULATORY MATTERS

See Note 2 to the financial statements in Item 8 of the Form 10-K for additional information relating to regulatory matters.

The recovery balances for certain of Alabama Power's, Georgia Power's, and Mississippi Power's regulatory clauses at June 30, 2019 and December 31, 2018 were as follows:

Regulatory Clause	Balance Sheet Line Item	June 30, 2019			December 31, 2018
		(in millions)
Alabama Power
Rate CNP Compliance	Deferred under recovered regulatory clause revenues	$	—		$	42
	Customer accounts receivable	10			—
Rate CNP PPA	Deferred under recovered regulatory clause revenues	25			25
Retail Energy Cost Recovery(*)	Deferred under recovered regulatory clause revenues	—			109
	Customer accounts receivable	8			—
Natural Disaster Reserve	Other regulatory liabilities, deferred	19			20
Georgia Power
Fuel Cost Recovery	Receivables – under recovered fuel clause revenues	$	69		$	115
Mississippi Power
Fuel Cost Recovery	Over recovered regulatory clause liabilities	$	9		$	8

(*)	In accordance with an accounting order issued on February 5, 2019 by the Alabama PSC, Alabama Power utilized $75 million of the 2018 Rate RSE refund liability to reduce the Rate ECR under recovered balance. See Note 2 to the financial statements under "Alabama Power – Rate ECR" in Item 8 of the Form 10-K for additional information.

Alabama Power

Environmental Accounting Order

On April 15, 2019, Alabama Power retired Plant Gorgas Units 8, 9, and 10 and reclassified approximately $654 million of the unrecovered asset balances to regulatory assets, which are being recovered over the units' remaining useful lives, the latest being through 2037, as established prior to the decision to retire. Additionally, approximately $700 million of net capitalized asset retirement costs were reclassified to a regulatory asset in accordance with accounting guidance provided by the Alabama PSC. The asset retirement costs are being recovered through 2055. See Note 2 to the financial statements under "Alabama Power – Environmental Accounting Order" and Note 6 in Item 8 of the Form 10-K for additional information.

Georgia Power

Rate Plans

On June 28, 2019, Georgia Power filed a base rate case (Georgia Power 2019 Base Rate Case) with the Georgia PSC. The filing includes a three-year Alternate Rate Plan with requested rate increases totaling $563 million, $145 million, and $234 million effective January 1, 2020, January 1, 2021, and January 1, 2022, respectively. These increases are based on a proposed retail ROE of 10.90% and a proposed equity ratio of 56% and reflect levelized revenue requirements during the three-year period, with the exception of incremental compliance costs related to CCR AROs, Demand-Side Management programs, and adjustments to the Municipal Franchise Fee tariff.

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(UNAUDITED)

Georgia Power has requested recovery of the proposed increases through its existing base rate tariffs as follows:

Tariff	2020			2021			2022
	(in millions)
Traditional base:
Levelized	$	209		$	—		$	—
CCR AROs	158			140			227
Environmental Compliance Cost Recovery	165			—			—
Demand-Side Management	14			2			1
Municipal Franchise Fee	17			3			5
Total(*)	$	563		$	145		$	234

(*)	Totals may not add due to rounding.

Georgia Power's filing primarily reflects requests to (i) address the impacts of the Tax Reform Legislation, (ii) recover the costs of recent and future capital investments in infrastructure designed to maintain high levels of reliability and superior customer service with updated depreciation rates, (iii) recover substantial storm damage expenses incurred and deferred since 2013 along with a reasonable level of storm damage expenses expected to be incurred during the three years ending December 31, 2022, and (iv) recover the costs necessary to comply with federal and state regulations for CCR AROs. In addition, the filing includes the following provisions:

•	Continuation of an allowed retail ROE range of 10.00% to 12.00%.

•	Continuation of the process whereby two-thirds of any earnings above the top of the allowed ROE range are shared with Georgia Power's customers and the remaining one-third are retained by Georgia Power.

•	Continuation of the option to file an Interim Cost Recovery tariff in the event earnings are projected to fall below the bottom of the ROE range during the three-year term of the plan.

Georgia Power expects the Georgia PSC to issue a final order in this matter on December 17, 2019. The ultimate outcome of this matter cannot be determined at this time.

Integrated Resource Plan

In 2016, the Georgia PSC approved Georgia Power's triennial Integrated Resource Plan, including recovery of costs up to $99 million through June 30, 2019 to preserve nuclear generation as an option at a future generation site in Stewart County, Georgia. In 2017, the Georgia PSC approved Georgia Power's decision to suspend work at the site due to changing economics, including lower load forecasts and fuel costs. In accordance with the Georgia PSC's order, costs incurred of approximately $50 million have been recorded as a regulatory asset.

On July 16, 2019, the Georgia PSC voted to approve Georgia Power's triennial Integrated Resource Plan (2019 IRP) as modified by a stipulated agreement among Georgia Power, the staff of the Georgia PSC, and certain intervenors and further modified by the Georgia PSC.

In the 2019 IRP, the Georgia PSC approved the decertification and retirement of Plant Hammond Units 1 through 4 (840 MWs) and Plant McIntosh Unit 1 (142.5 MWs) effective July 29, 2019. The Georgia PSC also approved the reclassification of the remaining net book values of the Plant Hammond and Plant McIntosh units (approximately $500 million and $40 million, respectively, at June 30, 2019), as well as any unusable materials and supplies inventory balances, upon retirement to a regulatory asset. Recovery of each unit's net book value will continue through December 31, 2019 as provided in the 2013 ARP.

For the regulatory asset balances remaining at December 31, 2019, Georgia Power requested recovery in the Georgia Power 2019 Base Rate Case as follows: (i) the net book values of Plant Mitchell Unit 3 (approximately $8 million at June 30, 2019) and Plant McIntosh Unit 1, any unusable materials and supplies inventory, and the future generation site in Stewart County, Georgia over a three-year period ending December 31, 2022 and (ii) the net book

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(UNAUDITED)

values of Plant Hammond Units 1 through 4 over a period equal to the applicable unit's remaining useful life through 2035. The ultimate outcome of these matters cannot be determined at this time.

Also in the 2019 IRP, the Georgia PSC rejected a request to certify approximately 25 MWs of capacity at Plant Scherer Unit 3 for the retail jurisdiction beginning January 1, 2020 following the expiration of a wholesale PPA. Georgia Power may offer such capacity in the wholesale market or to the retail jurisdiction in a future Integrated Resource Plan. The ultimate outcome of this matter cannot be determined at this time but is not expected to have a material impact on Georgia Power's or Southern Company's financial statements.

Additionally, the Georgia PSC approved Georgia Power's proposed environmental compliance strategy associated with ash pond and certain landfill closures and post-closure care in compliance with the CCR Rule and the related state rule. In the Georgia Power 2019 Base Rate Case, Georgia Power requested recovery of the under recovered balance of these compliance costs at December 31, 2019 (approximately $135 million at June 30, 2019) over a three-year period ending December 31, 2022 and recovery of estimated compliance costs of $277 million for 2020, $395 million for 2021, and $655 million for 2022 over three-year periods ending December 31, 2022, 2023, and 2024, respectively. The ultimate outcome of this matter cannot be determined at this time. See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information regarding Georgia Power's AROs.

The Georgia PSC also approved Georgia Power to (i) issue requests for proposals (RFP) for capacity beginning in 2022 or 2023 and in 2026, 2027, or 2028; (ii) procure up to an additional 2,210 MWs of renewable resources through competitive RFPs; and (iii) invest in a portfolio of up to 80 MWs of battery energy storage technologies.

See "Rate Plans" herein for additional information regarding the Georgia Power 2019 Base Rate Case.

Nuclear Construction

See Note 2 to the financial statements under "Georgia Power – Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding Georgia Power's construction of Plant Vogtle Units 3 and 4, the joint ownership agreements and related funding agreement, VCM reports, and the NCCR tariff.

In 2009, the Georgia PSC certified construction of Plant Vogtle Units 3 and 4. Georgia Power holds a 45.7% ownership interest in 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 other Vogtle Owners, entered into several transitional arrangements to allow construction to continue. In July 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into the Vogtle Services Agreement, whereby 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 provides that it 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, executed the Bechtel Agreement, 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,

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(UNAUDITED)

certain breaches of the Bechtel Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events.

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, 2019(b)	(5.2		)
Remaining estimate to complete(a)	$	3.2

(a)	Excludes financing costs expected to be capitalized through AFUDC of approximately $315 million.

(b)	Net of $1.7 billion received from Toshiba under the Guarantee Settlement Agreement and approximately $188 million in related Customer Refunds.

Georgia Power estimates that its financing costs for construction of Plant Vogtle Units 3 and 4 will total approximately $3.1 billion, of which $2.0 billion had been incurred through June 30, 2019.

In April 2019, Southern Nuclear completed a cost and schedule validation process to verify and update quantities of commodities remaining to install, labor hours to install remaining quantities and related productivity, testing and system turnover requirements, and forecasted staffing needs and related costs. This process confirmed the estimated total project capital cost forecast for Plant Vogtle Units 3 and 4. The expected in-service dates of November 2021 for Unit 3 and November 2022 for Unit 4, as previously approved by the Georgia PSC, remain unchanged.

As construction continues and testing and system turnover activities increase, challenges with management of contractors, subcontractors, and vendors; supervision of craft labor and related craft labor productivity, ability to attract and retain craft labor, and/or related cost escalation; procurement, fabrication, delivery, assembly, and/or installation and the initial testing and start-up, including any required engineering changes, of plant systems, structures, or components (some of which are based on new technology that only recently began initial operation in the global nuclear industry at this scale), or regional transmission upgrades, any of which may require additional labor and/or materials; or other issues could arise and change the projected schedule and estimated cost.

The April 2019 cost and schedule validation process established target values for monthly construction production and system turnover activities as part of a strategy to maintain and, where possible, build margin to the approved in-service dates. To support that strategy, monthly production and activity target values will continue to increase significantly throughout 2019. To meet these increasing monthly targets, existing craft construction productivity must improve and additional craft laborers (particularly electrical and pipefitter craft labor), as well as additional supervision and other field support resources, must be retained and deployed.

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 submittal by Southern Nuclear of the ITAAC documentation for each unit and the related reviews and approvals by the NRC necessary to support NRC authorization to load fuel, 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.

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The ultimate outcome of these matters cannot be determined at this time. However, any extension of the regulatory-approved 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 to provide for, among other conditions, additional Vogtle Owner approval requirements. Effective in August 2018, the Vogtle Owners further amended the joint ownership agreements to clarify and provide procedures for certain provisions of the joint ownership agreements related to adverse events that require the vote of the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 to continue construction (as amended, and together with the November 2017 amendment, the Vogtle Joint Ownership Agreements). 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 in conjunction with the nineteenth VCM report, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 were required to vote to continue construction. In September 2018, the Vogtle Owners unanimously voted to continue construction of Plant Vogtle Units 3 and 4.

Amendments to the Vogtle Joint Ownership Agreements

In connection with the vote to continue construction, Georgia Power entered into (i) a binding term sheet (Vogtle Owner Term Sheet) with the other Vogtle Owners and MEAG's wholly-owned subsidiaries MEAG Power SPVJ, LLC (MEAG SPVJ), MEAG Power SPVM, LLC (MEAG SPVM), and MEAG Power SPVP, LLC (MEAG SPVP) to take certain actions which partially mitigate potential financial exposure for the other Vogtle Owners, including additional amendments to the Vogtle Joint Ownership Agreements and the purchase of PTCs from the other Vogtle Owners at pre-established prices, and (ii) a term sheet (MEAG Term Sheet) with MEAG and MEAG SPVJ to provide funding with respect to MEAG SPVJ's ownership interest in Plant Vogtle Units 3 and 4 under certain circumstances. On January 14, 2019, Georgia Power, MEAG, and MEAG SPVJ entered into an agreement to implement the provisions of the MEAG Term Sheet. On February 18, 2019, Georgia Power, the other Vogtle Owners, and MEAG's wholly-owned subsidiaries MEAG SPVJ, MEAG SPVM, and MEAG SPVP entered into certain amendments to the Vogtle Joint Ownership Agreements to implement the provisions of the Vogtle Owner Term Sheet.

The ultimate outcome of these matters 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. At June 30, 2019, Georgia Power had recovered approximately $2.0 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. In December 2018, the Georgia PSC approved Georgia Power's request to increase the NCCR tariff by $88 million annually, effective January 1, 2019.

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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) Georgia Power's seventeenth VCM report and modified 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 related 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 $100 million in 2018 and are estimated to have negative earnings impacts of approximately $70 million in 2019 and an aggregate of approximately $630 million from 2020 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.

In February 2018, Georgia Interfaith Power & Light, Inc. (GIPL) and Partnership for Southern Equity, Inc. (PSE) filed a petition appealing the Georgia PSC's January 11, 2018 order with the Fulton County Superior Court. In March 2018, Georgia Watch filed a similar appeal to the Fulton County Superior Court for judicial review of the Georgia PSC's decision and denial of Georgia Watch's motion for reconsideration. In December 2018, the Fulton County Superior Court granted Georgia Power's motion to dismiss the two appeals. On January 9, 2019, GIPL, PSE, and Georgia Watch filed an appeal of this decision with the Georgia Court of Appeals. Georgia Power believes the appeal has no merit; however, an adverse outcome in the appeal combined with subsequent adverse action by the Georgia PSC could have a material impact on Southern Company's and Georgia Power's results of operations, financial condition, and liquidity.

In August 2018, Georgia Power filed its nineteenth VCM report with the Georgia PSC, which requested approval of $578 million of construction capital costs incurred from January 1, 2018 through June 30, 2018. On February 19, 2019, the Georgia PSC approved the nineteenth VCM, but deferred approval of $51.6 million of expenditures

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related to Georgia Power's portion of an administrative claim filed in the Westinghouse bankruptcy proceedings. Through the nineteenth VCM, the Georgia PSC has approved total construction capital costs incurred through June 30, 2018 of $5.4 billion (before $1.7 billion of payments received under the Guarantee Settlement Agreement and approximately $188 million in related Customer Refunds).

On April 30, 2019, as requested by the staff of the Georgia PSC, Georgia Power reported the results of the cost and schedule validation process to the Georgia PSC. On August 30, 2019, Georgia Power will file its twentieth VCM report concurrently with its twenty-first VCM report with the Georgia PSC, which will reflect the capital cost forecast discussed previously and request approval of $1.2 billion of construction capital costs incurred from June 30, 2018 through June 30, 2019. In addition, on June 20, 2019, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into a settlement agreement related to the administrative claim filed in the Westinghouse bankruptcy proceedings. Accordingly, in the twentieth/twenty-first VCM report, Georgia Power will also request approval of the $51.6 million of associated expenditures previously deferred by the Georgia PSC.

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

DOE Financing

At June 30, 2019, Georgia Power had borrowed $3.46 billion related to Plant Vogtle Units 3 and 4 costs as provided through the Amended and Restated Loan Guarantee Agreement and related multi-advance credit facilities among Georgia Power, the DOE, and the FFB, which provide for borrowings of up to approximately $5.130 billion, subject to the satisfaction of certain conditions. See Note 8 to the financial statements under "Long-term Debt – 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, and conditions to borrowing.

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

Mississippi Power

Municipal and Rural Association Tariff

On May 7, 2019, the FERC accepted Mississippi Power's March 28, 2019 request for a decrease in wholesale base revenues under the MRA tariff as agreed upon in a settlement agreement reached with its wholesale customers resolving all matters related to the Kemper County energy facility similar to the retail rate settlement agreement approved by the Mississippi PSC in February 2018 and reflecting the impacts of the Tax Reform Legislation. Pursuant to the MRA settlement agreement, base rates decreased $3.7 million annually, effective January 1, 2019.

Environmental Compliance Overview Plan

On July 9, 2019, Mississippi Power filed a request with the Mississippi PSC for a Certificate of Public Convenience and Necessity to complete certain environmental compliance projects, primarily associated with the Plant Daniel coal units co-owned 50% with Gulf Power. The total estimated cost is approximately $125 million, with Mississippi Power's share of approximately $66 million being proposed for recovery through its ECO Plan. Approximately $17 million of Mississippi Power's share is associated with ash pond closure and is reflected in Mississippi Power's ARO liabilities. See Note 2 to the financial statements under "Mississippi Power – Environmental Compliance Overview Plan" in Item 8 of the Form 10-K for additional information on Mississippi Power's ECO Plan. See Note (A) under "Asset Retirement Obligations" for additional information on AROs and Note (C) under "Other Matters – Mississippi Power" herein for additional information on Gulf Power's ownership in Plant Daniel.

Kemper County Energy Facility

As the mining permit holder, Liberty Fuels Company, LLC has a legal obligation to perform mine reclamation, and Mississippi Power has a contractual obligation to fund all reclamation activities. As a result of the abandonment of the Kemper IGCC, final mine reclamation began in 2018 and is expected to be substantially completed in 2020,

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with monitoring expected to continue through 2027. See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information.

During the second quarter and year-to-date 2019, Mississippi Power recorded pre-tax charges to income of $4 million ($3 million after tax) and $6 million ($5 million after tax), respectively, primarily resulting from the abandonment and related closure activities and ongoing period costs, net of sales proceeds, 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 at up to $10 million pre-tax (excluding dismantlement costs, net of salvage), may be incurred through the first half of 2020. 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 $7 million for the remainder of 2019 and $2 million to $6 million annually in 2020 through 2023.

In addition, Mississippi Power constructed the CO₂ pipeline for the planned transport of captured CO₂ for use in enhanced oil recovery and is currently evaluating its options regarding the final disposition of the CO₂ pipeline, including removal of the pipeline. This evaluation is expected to be complete later in 2019. If Mississippi Power ultimately decides to remove the CO₂ pipeline, the cost of removal would have a material impact on Mississippi Power's financial statements and could have a material impact on Southern Company's financial statements.

In December 2018, Mississippi Power filed with the DOE its request for property closeout certification under the contract related to the $387 million of grants received. Mississippi Power and the DOE are currently in discussions regarding the requested closeout and property disposition, which may require payment to the DOE for a portion of certain property that is to be retained by Mississippi Power. In connection with the DOE closeout discussions, on April 29, 2019, the Civil Division of the Department of Justice informed Southern Company and Mississippi Power of an investigation related to the Kemper County energy facility. The ultimate outcome of these matters cannot be determined at this time; however, they could have a material impact on Mississippi Power's and Southern Company's financial statements.

Southern Company Gas

Rate Proceedings

Nicor Gas

In November 2018, Nicor Gas filed a general base rate case with the Illinois Commission requesting a $230 million increase in annual base rate revenues. The requested increase is based on a projected test year for the 12-month period ending September 30, 2020, a ROE of 10.6%, and an increase in the equity ratio from 52% to 54% to address the negative cash flow and credit metric impacts of the Tax Reform Legislation.

On April 16, 2019, Nicor Gas entered into a stipulation agreement to resolve all related issues with the Staff of the Illinois Commission, including a ROE of 9.86% and an equity ratio of 54%. Also on April 16, 2019, Nicor Gas filed its rebuttal testimony with the Illinois Commission incorporating the stipulation agreement and addressing the remaining items outstanding with the other two intervenors. As a result of the stipulation agreement and rebuttal testimony, the revised requested annual revenue increase is $180 million.

The Illinois Commission is expected to rule on the requested increase by early October 2019, after which rate adjustments will be effective. The ultimate outcome of this matter cannot be determined at this time.

Atlanta Gas Light

On June 3, 2019, Atlanta Gas Light filed a general base rate case with the Georgia PSC requesting a $96 million increase in annual base rate revenues. The requested increase is based on a forward-looking test year for the 12-month period ending July 31, 2020, a ROE of 10.75% with an earnings band based on a ROE between 10.55% and 10.95%, and a continued equity ratio of 55%. The filing also requests the continuation of the Georgia rate adjustment mechanism, as previously authorized. Atlanta Gas Light expects the Georgia PSC to issue a final order on this matter on December 19, 2019 with the new rates becoming effective January 1, 2020. The ultimate outcome of this matter cannot be determined at this time.

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Virginia Natural Gas

In December 2018, the Virginia Commission approved Virginia Natural Gas' annual information form filing, which reduced annual base rates by $14 million effective January 1, 2019 due to lower tax expense as a result of the Tax Reform Legislation. This approval also required Virginia Natural Gas to issue customer refunds, via bill credits, for $14 million related to 2018 tax benefits deferred as a regulatory liability, current, on the balance sheet at December 31, 2018. These customer refunds were completed in the first quarter 2019.

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. In addition to capital expenditures recovered through base rates by each of the natural gas distribution utilities, Nicor Gas and Virginia Natural Gas have separate rate riders that provide for timely recovery of capital expenditures for specific infrastructure replacement programs.

Virginia Natural Gas

On April 8, 2019, Virginia Natural Gas filed an application with the Virginia Commission to amend and extend its Steps to Advance Virginia's Energy program. The proposal would allow Virginia Natural Gas to continue replacing aging pipeline infrastructure and increase its authorized investment under the currently-approved plan. Virginia Natural Gas seeks to amend its currently-approved plan by increasing the authorized investment in 2019 from $35 million to $40 million and to extend the plan for an additional five years until 2024, with proposed annual investments of $50 million in 2020, $60 million in 2021, and $70 million in each year from 2022 through 2024, for a maximum total investment over the six-year term (2019 through 2024) of $370 million. The proposed investment schedule would also allow for variances of up to $6 million in 2019, $8 million in 2020, $9 million in 2021, and $10 million in each year from 2022 through 2024, with a total potential net variance of up to $10 million allowed for the program. The Virginia Commission is expected to rule on the request in the fourth quarter 2019. The ultimate outcome of this matter cannot be determined at this time.

Affiliate Asset Management Agreements

On March 15, 2019, the Virginia Commission approved an extension of Virginia Natural Gas' asset management agreement with Sequent to March 31, 2021.

FERC Matters

See Note 2 to the financial statements under "FERC Matters – Open Access Transmission Tariff" in Item 8 of the Form 10-K for additional information.

On June 28, 2019, the FERC approved a settlement agreement between Alabama Municipal Electric Authority and Cooperative Energy and SCS and the traditional electric operating companies agreeing to an OATT rate reduction based on a 10.6% ROE, with a retroactive effective date of May 10, 2018, and a five-year moratorium on these parties seeking changes to the OATT formula rate. The terms of the OATT settlement agreement will not have a material impact on the financial statements of any of the traditional electric operating companies or Southern Company.

(C) CONTINGENCIES

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

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

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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 determined 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 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 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. Also in 2017, the defendants filed a motion to dismiss the plaintiffs' amended complaint with prejudice, to which the plaintiffs filed an opposition. In March 2018, the court 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. In April 2018, the defendants filed a motion for reconsideration of the court's order, seeking dismissal of the remaining claims in the lawsuit. In August 2018, the court denied the motion for reconsideration and denied a motion to certify the issue for interlocutory appeal.

In February 2017, Jean Vineyard and Judy Mesirov each filed a shareholder derivative lawsuit 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 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. In April 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, 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. In May 2018, the court entered an

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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. The ultimate outcome of these matters 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 amounts for municipal franchise fees (which fees are paid 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 2017. In June 2018, the Georgia Supreme Court affirmed the judgment of the Georgia Court of Appeals and remanded the case to the trial court for further proceedings. Following a motion by Georgia Power, on February 13, 2019, the Superior Court of Fulton County ordered the parties to submit petitions to the Georgia PSC for a declaratory ruling to address certain terms the court previously held were ambiguous as used in the Georgia PSC's orders. The order entered by the Superior Court of Fulton County also conditionally certified the proposed class. In March 2019, Georgia Power and the plaintiffs filed petitions with the Georgia PSC seeking confirmation of the proper application of the municipal franchise fee schedule pursuant to the Georgia PSC's orders. Georgia Power also filed a notice of appeal with the Georgia Court of Appeals regarding the Superior Court of Fulton County's February 2019 order. Georgia Power believes the plaintiffs' claims have no merit. The amount of any possible losses cannot be calculated at this time because, among other factors, it is unknown whether conditional class certification will be upheld and the ultimate composition of any class 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 May 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 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. In the first quarter 2019, Mississippi Power and Southern Company filed motions to dismiss, which were denied by the arbitration panel on May 10, 2019. 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. The ultimate outcome of this matter cannot be determined at this time.

In November 2018, Ray C. Turnage and 10 other individual plaintiffs filed a putative class action complaint against Mississippi Power and the three current members of the Mississippi PSC in the U.S. District Court for the Southern District of Mississippi. Mississippi Power received Mississippi PSC approval in 2013 to charge a mirror CWIP rate premised upon including in its rate base pre-construction and construction costs for the Kemper IGCC prior to placing the Kemper IGCC into service. The Mississippi Supreme Court reversed that approval and ordered Mississippi Power to refund the amounts paid by customers under the previously-approved mirror CWIP rate. The plaintiffs allege that the initial approval process, and the amount approved, were improper. They also allege that Mississippi Power underpaid customers by up to $23.5 million in the refund process by applying an incorrect interest rate. The plaintiffs seek to recover, on behalf of themselves and their putative class, actual damages, punitive damages, pre-judgment interest, post-judgment interest, attorney's fees, and costs. In response to Mississippi Power and the Mississippi PSC each filing a motion to dismiss, the plaintiffs filed an amended complaint on March 14, 2019. The amended complaint included four additional plaintiffs and additional claims for

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gross negligence, reckless conduct, and intentional wrongdoing. Mississippi Power and the Mississippi PSC have each filed a motion to dismiss the amended complaint. Mississippi Power believes this legal challenge has no merit; however, an adverse outcome in this proceeding could have a material impact on Mississippi Power's results of operations, financial condition, and liquidity. The ultimate outcome of this matter cannot be determined at this time.

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 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 connection therewith, Southern Power withheld payment of approximately $26 million to the construction contractor, which placed a lien on the Roserock facility for the same amount. In 2017, Roserock filed a lawsuit in the state district court in Pecos County, Texas against XL Insurance America, Inc. and North American Elite Insurance Company seeking recovery from an insurance policy for damages resulting from the hail event and McCarthy's installation practices. In June 2018, the court 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. Separate lawsuits were filed between Roserock and McCarthy, as well as other parties, and that litigation was consolidated in the U.S. District Court for the Western District of Texas. On April 18, 2019, Roserock and the parties to the state and federal lawsuits executed a settlement agreement and mutual release that resolved both lawsuits. Following execution of the agreement, the lawsuits were dismissed, Southern Power paid McCarthy the amounts previously withheld, and McCarthy released its lien. As part of the settlement, Roserock received funds that covered all related legal costs, damages, and the replacement costs of certain solar panels. Funds received by Southern Power in excess of the initial replacement costs were recognized as a gain and included in other income (expense), net in 2019. A portion of the pre-tax gain was allocated to noncontrolling interests and Southern Power recognized a $12 million after-tax gain.

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 and Georgia have each 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 $18 million and $23 million as of June 30, 2019 and December 31, 2018, 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.

Southern Company Gas' environmental remediation liability was $283 million and $294 million as of June 30, 2019 and December 31, 2018, respectively, based on the estimated cost of environmental investigation and remediation associated with known current and former manufactured gas plant operating sites. 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.

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, or Southern Company Gas.

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Nuclear Fuel Disposal Costs

In 2014, Alabama Power and Georgia Power filed lawsuits against the U.S. government for the costs of continuing to store spent nuclear fuel at Plants Farley, Hatch, and Vogtle Units 1 and 2 for the period from January 1, 2011 through December 31, 2013. The damage period was subsequently extended to December 31, 2014. On June 12, 2019, the Court of Federal Claims granted Alabama Power's and Georgia Power's motion for summary judgment on damages not disputed by the U.S. government, awarding those undisputed damages to Alabama Power and Georgia Power. However, those undisputed damages are not collectible and no amounts will be recognized in the financial statements until the court enters final judgment on the remaining damages. The final outcome of these matters cannot be determined at this time. However, Alabama Power and Georgia Power expect to credit any recoveries for the benefit of customers in accordance with direction from their respective PSC; therefore, no material impact on Southern Company's, Alabama Power's, or Georgia Power's net income is expected.

Other Matters

Alabama Power

On May 17, 2019, the Alabama Department of Environmental Management (ADEM) issued a proposed administrative order assessing a penalty of $250,000 to Alabama Power for unpermitted discharge of fluids and/or pollutants to groundwater and/or soils at Plant Gadsden. The proposed order also requires the submission to the ADEM of a plan with a schedule for implementation of a comprehensive groundwater investigation, an assessment of corrective measures, a report evaluating any deficiencies at the facility that may have led to the unpermitted discharge, and quarterly progress reports. Alabama Power is awaiting finalization of the order and the ultimate outcome of this matter cannot be determined at this time; however, it is not expected to have a material impact on Alabama Power's net income.

Mississippi Power

In conjunction with Southern Company's sale of Gulf Power, Mississippi Power and Gulf Power have committed to seek a restructuring of their 50% undivided ownership interests in Plant Daniel such that each of them would, after the restructuring, own 100% of a generating unit. On January 15, 2019, Gulf Power provided notice to Mississippi Power that Gulf Power will retire its share of the generating capacity of Plant Daniel on January 15, 2024. Mississippi Power has the option to purchase Gulf Power's ownership interest for $1 on January 15, 2024, provided that Mississippi Power exercises the option no later than 120 days prior to that date. Mississippi Power is assessing the potential operational and economic effects of Gulf Power's notice. The ultimate outcome of these matters remains subject to completion of Mississippi Power's evaluations and applicable regulatory approvals, including by the FERC and the Mississippi PSC, and cannot be determined at this time. See Note (K) under "Southern Company" for information regarding the sale of Gulf Power.

Southern Company Gas

The future performance of Southern Company Gas' natural gas storage facility consisting of two salt dome caverns in Louisiana, as well as Southern Company Gas' two other natural gas storage facilities located in California and Texas, could be impacted by ongoing changes in the U.S. natural gas storage market. Recent sales of natural gas storage facilities have resulted in losses for the sellers and may imply an impact on future rates and/or asset values. Southern Company Gas is evaluating these recent market transactions for impacts on its plans to return one of the salt dome caverns in Louisiana back to service in 2021. Sustained diminished natural gas storage values could trigger impairment of one or all of these natural gas storage facilities, which have a combined net book value of $438 million at June 30, 2019. The ultimate outcome of these matters cannot be determined at this time, but could have a material impact on Southern Company's and Southern Company Gas' financial statements.

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(D) 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, Revenue from Contracts with Customers (ASC 606), such as leases, derivatives, and certain cost recovery mechanisms. See Note 1 to the financial statements under "Recently Adopted Accounting Standards – Revenue" in Item 8 of the Form 10-K for additional information on the adoption of ASC 606 for revenue from contracts with customers and Note 1 to the financial statements under "Revenues" and "Other Taxes" in Item 8 of the Form 10-K for additional information on the revenue policies of the registrants. For additional information on revenues accounted for under other accounting guidance, see Notes (J) and (L) for energy-related derivative contracts and lessor revenues, respectively, Note 1 to the financial statements under "Revenues – Southern Company Gas" in Item 8 of the Form 10-K for alternative revenue programs at the natural gas distribution utilities, and Note 2 to the financial statements in Item 8 of the Form 10-K for cost recovery mechanisms.

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The following tables disaggregate revenue sources for the three and six months ended June 30, 2019 and 2018:

	For the Three Months Ended June 30, 2019			For the Three Months Ended June 30, 2018			For the Six Months Ended June 30, 2019			For the Six Months Ended June 30, 2018
	(in millions)
Southern Company
Operating revenues
Retail electric revenues(a)
Residential	$	1,488		$	1,579		$	2,776		$	3,118
Commercial	1,258			1,315			2,350			2,557
Industrial	763			814			1,440			1,569
Other	31			32			57			64
Natural gas distribution revenues(b)	562			642			1,724			1,865
Alternative revenue programs(c)	1			(4		)	—			(27		)
Total retail electric and gas distribution revenues	$	4,103		$	4,378		$	8,347		$	9,146
Wholesale energy revenues(d)(e)	410			464			777			937
Wholesale capacity revenues(e)	132			152			264			302
Other natural gas revenues(f)(g)	126			68			439			476
Other revenues(h)	327			565			683			1,138
Total operating revenues	$	5,098		$	5,627		$	10,510		$	11,999

(a)

Retail electric revenues include $8 million, $18 million, $16 million, and $36 million of revenues accounted for as leases for the three months ended June 30, 2019 and 2018 and the six months ended June 30, 2019 and 2018, respectively, and a (net reduction) or net increase of $(14) million, $68 million, $(117) million and $101 million for the three months ended June 30, 2019 and 2018 and the six months ended June 30, 2019 and 2018, respectively, from certain cost recovery mechanisms that are not accounted for as revenue under ASC 606.

(b)	Natural gas distribution revenues include $5 million for each of the three months ended June 30, 2019 and 2018 and $8 million for each of the six months ended June 30, 2019 and 2018 of revenues not accounted for under ASC 606.

(c)	Alternative revenue program revenues are presented net of any previously recognized program amounts billed to customers during the same accounting period.

(d)	Wholesale energy revenues include $30 million, $61 million, $82 million, and $155 million of revenues accounted for as derivatives for the three months ended June 30, 2019 and 2018 and the six months ended June 30, 2019 and 2018, respectively, primarily related to physical energy sales in the wholesale electricity market.

(e)

Wholesale energy revenues include $115 million, $118 million, $182 million, and $187 million for the three months ended June 30, 2019 and 2018 and the six months ended June 30, 2019 and 2018, respectively, and wholesale capacity revenues include $22 million, $31 million, $47 million, and $61 million for the three months ended June 30, 2019 and 2018 and the six months ended June 30, 2019 and 2018, respectively, related to PPAs accounted for as leases.

(f)

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 $1.2 billion, $1.3 billion, $3.1 billion, and $3.3 billion for the three months ended June 30, 2019 and 2018 and the six months ended June 30, 2019 and 2018, respectively, of which $0.8 billion, $0.7 billion, $2.0 billion, and $1.8 billion, respectively, relates to contracts that are accounted for as derivatives. See Note (M) under "Southern Company Gas" for additional information on the components of wholesale gas services operating revenues.

(g)	Other natural gas revenues include $10 million and $27 million for the three and six months ended June 30, 2019, respectively, of revenues not accounted for under ASC 606, including $8 million and $16 million, respectively, of revenues accounted for as leases.

(h)	Other revenues include $89 million, $89 million, $180 million, and $183 million for the three months ended June 30, 2019 and 2018 and the six months ended June 30, 2019 and 2018, respectively, of revenues not accounted for under ASC 606, including $28 million, $33 million, $59 million, and $66 million, respectively, accounted for as leases.

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	Alabama Power			Georgia Power			Mississippi Power
	(in millions)
For the Three Months Ended June 30, 2019
Operating revenues
Retail revenues(a)(b)
Residential	$	588		$	831		$	69
Commercial	418			767			73
Industrial	366			327			70
Other	6			21			3
Total retail electric revenues	$	1,378		$	1,946		$	215
Wholesale energy revenues(c)	41			14			93
Wholesale capacity revenues	25			22			1
Other revenues(b)(d)	69			135			4
Total operating revenues	$	1,513		$	2,117		$	313
For the Three Months Ended June 30, 2018
Operating revenues
Retail revenues(a)(b)
Residential	$	557		$	785		$	65
Commercial	402			749			68
Industrial	372			335			76
Other	7			20			3
Total retail electric revenues	$	1,338		$	1,889		$	212
Wholesale energy revenues(c)	71			26			77
Wholesale capacity revenues	25			13			1
Other revenues(b)(d)	69			120			7
Total operating revenues	$	1,503		$	2,048		$	297

(a)

Retail revenues at Alabama Power, Georgia Power, and Mississippi Power include a net increase or (net reduction) of $(11) million, $(5) million, and $2 million, respectively, for the three months ended June 30, 2019 and $78 million, $3 million, and $(1) million, respectively, for the three months ended June 30, 2018 related to certain cost recovery mechanisms that are not accounted for as revenue under ASC 606.

(b)	Retail revenues and other revenues at Georgia Power include $8 million and $11 million, respectively, for the three months ended June 30, 2019 and $18 million and $33 million, respectively, for the three months ended June 30, 2018 of revenues accounted for as leases.

(c)	Wholesale energy revenues at Alabama Power, Georgia Power, and Mississippi Power include $3 million, $4 million, and $1 million, respectively, for the three months ended June 30, 2019 and $4 million, $5 million, and $1 million, respectively, for the three months ended June 30, 2018 accounted for as derivatives primarily related to physical energy sales in the wholesale electricity market.

(d)	Other revenues at Alabama Power and Georgia Power include $31 million and $30 million, respectively, for the three months ended June 30, 2019 and $26 million and $26 million, respectively, for the three months ended June 30, 2018 of revenues not accounted for under ASC 606.

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	Alabama Power			Georgia Power			Mississippi Power
	(in millions)
For the Six Months Ended June 30, 2019
Operating revenues
Retail revenues(a)(b)
Residential	$	1,128		$	1,519		$	129
Commercial	772			1,440			138
Industrial	679			616			145
Other	13			39			6
Total retail electric revenues	$	2,592		$	3,614		$	418
Wholesale energy revenues(c)	135			27			170
Wholesale capacity revenues	51			40			2
Other revenues(b)(d)	143			270			10
Total operating revenues	$	2,921		$	3,951		$	600
For the Six Months Ended June 30, 2018
Operating revenues
Retail revenues(a)(b)
Residential	$	1,127		$	1,529		$	125
Commercial	774			1,466			130
Industrial	710			650			146
Other	13			43			5
Total retail electric revenues	$	2,624		$	3,688		$	406
Wholesale energy revenues(c)	172			66			176
Wholesale capacity revenues	49			27			5
Other revenues(b)(d)	131			227			11
Total operating revenues	$	2,976		$	4,008		$	598

(a)

Retail revenues at Alabama Power, Georgia Power, and Mississippi Power include a net increase or (net reduction) of $(68) million, $(52) million, and $3 million, respectively, for the six months ended June 30, 2019 and $125 million, $12 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.

(b)	Retail revenues and other revenues at Georgia Power include $16 million and $23 million, respectively, for the six months ended June 30, 2019 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, Georgia Power, and Mississippi Power include $6 million, $8 million, and $1 million, respectively, for the six months ended June 30, 2019 and $9 million, $13 million, and $2 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.

(d)	Other revenues at Alabama Power and Georgia Power include $59 million and $61 million, respectively, for the six months ended June 30, 2019 and $52 million and $53 million, respectively, for the six months ended June 30, 2018 of revenues not accounted for under ASC 606.

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	For the Three Months Ended June 30, 2019			For the Three Months Ended June 30, 2018			For the Six Months Ended June 30, 2019			For the Six Months Ended  June 30, 2018
	(in millions)
Southern Power
PPA capacity revenues(a)	$	125		$	144		$	252		$	282
PPA energy revenues(a)	291			302			518			556
Non-PPA revenues(b)	91			106			177			221
Other revenues	3			3			6			5
Total operating revenues	$	510		$	555		$	953		$	1,064

(a)

PPA capacity revenues include $39 million, $47 million, $80 million, and $94 million for the three months ended June 30, 2019 and 2018 and the six months ended June 30, 2019 and 2018, respectively, and PPA energy revenues include $125 million, $127 million, $198 million, and $203 million for the three months ended June 30, 2019 and 2018 and the six months ended June 30, 2019 and 2018, respectively, related to PPAs accounted for as leases.

(b)	Non-PPA revenues include $22 million, $50 million, $67 million, and $129 million for the three months ended June 30, 2019 and 2018 and the six months ended June 30, 2019 and 2018, respectively, of revenues from short-term sales related to physical energy sales from uncovered capacity in the wholesale electricity market.

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	For the Three Months Ended June 30, 2019			For the Three Months Ended June 30, 2018			For the Six Months Ended June 30, 2019			For the Six Months Ended  June 30, 2018
	(in millions)
Southern Company Gas
Operating revenues
Natural gas distribution revenues(a)
Residential	$	229		$	273		$	830		$	933
Commercial	65			76			235			268
Transportation	213			228			469			505
Industrial	5			7			22			24
Other	50			58			168			135
Alternative revenue programs(b)	1			(4		)	—			(27		)
Total natural gas distribution revenues	$	563		$	638		$	1,724		$	1,838
Gas pipeline investments(c)	8			8			16			16
Wholesale gas services(d)	48			(15		)	114			131
Gas marketing services(e)	58			89			287			359
Other revenues	12			10			22			25
Total operating revenues	$	689		$	730		$	2,163		$	2,369

(a)	Natural gas distribution revenues include $5 million for each of the three months ended June 30, 2019 and 2018 and $8 million for each of the six months ended June 30, 2019 and 2018 of revenues not accounted for under ASC 606.

(b)	Alternative revenue program revenues are presented net of any previously recognized program amounts billed to customers during the same accounting period.

(c)	Revenues from gas pipeline investments include $8 million and $16 million for the three and six months ended June 30, 2019, respectively, accounted for as leases.

(d)

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 $1.2 billion, $1.3 billion, $3.1 billion, and $3.3 billion for the three months ended June 30, 2019 and 2018 and the six months ended June 30, 2019 and 2018, respectively, of which $0.8 billion, $0.7 billion, $2.0 billion, and $1.8 billion, respectively, relates to contracts accounted for as derivatives. See Note (M) under "Southern Company Gas" for additional information on the components of wholesale gas services operating revenues.

(e)	Gas marketing services include $2 million for the three months ended June 30, 2019 and $11 million and $4 million for the six months ended June 30, 2019 and 2018, respectively, of revenues not accounted for under ASC 606.

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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, 2019 and December 31, 2018:

	Receivables							Contract Assets							Contract Liabilities
	June 30, 2019			December 31, 2018				June 30, 2019			December 31, 2018				June 30, 2019			December 31, 2018
	(in millions)
Southern Company(*)	$	2,343		$	2,630			$	70		$	102			$	58		$	32
Alabama Power	629			520				—			—				10			12
Georgia Power	807			721				30			58				26			7
Mississippi Power	93			100				—			—				7			—
Southern Power	119			118				—			—				1			11
Southern Company Gas	550			952				—			—				1			2

(*)	Includes amounts related to held for sale investments.

As of June 30, 2019 and December 31, 2018, Georgia Power had contract assets primarily related to unregulated service agreements where payment is contingent on project completion and 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. Alabama Power had contract liabilities for outstanding performance obligations primarily related to extended service agreements. Contract liabilities for Georgia Power and Southern Power relate to cash collections recognized in advance of revenue for certain unregulated service agreements and certain levelized PPAs, respectively. Mississippi Power had contract liabilities for cash collections recognized in advance of revenue for operating agreements associated with a tolling arrangement accounted for as a sales-type lease. Southern Company's unregulated distributed generation business had $32 million and $39 million of contract assets and $14 million and $11 million of contract liabilities at June 30, 2019 and December 31, 2018, respectively, remaining for outstanding performance obligations.

The following table reflects revenue from contracts with customers recognized in the three and six months ended June 30, 2019 included in the contract liability at December 31, 2018:

	Three Months Ended June 30, 2019			Six Months Ended June 30, 2019
	(in millions)
Southern Company	$	11		$	27
Southern Power	1			11

Revenues recognized in the three and six months ended June 30, 2019, which were included in contract liabilities at December 31, 2018, were immaterial for Alabama Power, Georgia Power, and Southern Company Gas.

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Remaining Performance Obligations

The traditional electric operating companies and Southern Power have long-term contracts with customers in which revenues are recognized when the performance obligations are satisfied during 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. Registrants with revenues from contracts with customers related to these performance obligations remaining at June 30, 2019 expect the revenues to be recognized as follows:

	2019 (remaining)			2020			2021			2022			2023			Thereafter
	(in millions)
Southern Company	$	282		$	490		$	320		$	311		$	302		$	2,230
Alabama Power	11			23			27			23			22			140
Georgia Power	27			51			44			31			31			83
Southern Power	169			295			270			276			269			2,154

Revenues expected to be recognized for performance obligations remaining at June 30, 2019 were immaterial for Mississippi Power.

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(E) CONSOLIDATED ENTITIES AND EQUITY METHOD INVESTMENTS

Southern Power

Consolidated Variable Interest Entities

See Note 7 to the financial statements in Item 8 of the Form 10-K for additional information on Southern Power's consolidated VIEs.

Southern Power has certain subsidiaries that are determined to be VIEs. Southern Power is considered the primary beneficiary of these VIEs because it controls the most significant activities of the VIEs, including operating and maintaining the respective assets, and has the obligation to absorb expected losses of these VIEs to the extent of its equity interests. In 2018, Southern Power sold noncontrolling interests in SP Solar and SP Wind. Southern Power continues to consolidate each entity, as the primary beneficiary of each VIE, since it controls the most significant activities of each entity, including operating and maintaining their assets. Transfers and sales of the assets in the VIEs are subject to limited partner consent and the liabilities are non-recourse to the general credit of Southern Power. Liabilities consist of customary working capital items and do not include any long-term debt.

SP Solar

At June 30, 2019, SP Solar had total assets of $6.5 billion, total liabilities of $374 million, and noncontrolling interests of $1.1 billion. Cash distributions from SP Solar are allocated 67% to Southern Power and 33% to Global Atlantic in accordance with their partnership interest percentage. Under the terms of the limited partnership agreement, distributions without limited partner consent are limited to available cash and SP Solar is obligated to distribute all such available cash to its partners each quarter. Available cash includes all cash generated in the quarter subject to the maintenance of appropriate operating reserves.

SP Wind

At June 30, 2019, SP Wind had total assets of $2.5 billion, total liabilities of $136 million, and noncontrolling interests of $46 million. Under the terms of the limited liability agreement, distributions without Class A member consent are limited to available cash and SP Wind is obligated to distribute all such available cash to its members each quarter. Available cash includes all cash generated in the quarter subject to the maintenance of appropriate operating reserves. Cash distributions from SP Wind are generally allocated 60% to Southern Power and 40% to the three financial investors in accordance with the limited liability agreement.

Equity Method Investments

In June 2019, Southern Power made investments in certain legal entities that are considered VIEs but for which Southern Power is not the primary beneficiary because it does not control the most significant activities of the VIEs. These investments are accounted for as equity method investments. The total carrying amount of these investments is $144 million as of June 30, 2019, of which $116 million relates to membership interests in DSGP, an affiliate of Bloom Energy, that owns and operates fuel cell generation facilities in Delaware. Southern Power expects to consolidate DSGP, and record a noncontrolling interest, pending FERC approval of the transfer of the facilities. FERC approval is expected to occur in the third quarter 2019; however, the ultimate outcome of this matter cannot be determined at this time.

Southern Company Gas

See Note 7 to the financial statements in Item 8 of the Form 10-K for additional information on Southern Company Gas' equity method investments.

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Equity Method Investments

The carrying amounts of Southern Company Gas' equity method investments as of June 30, 2019 and December 31, 2018 and related income from those investments for the three- and six-month periods ended June 30, 2019 and 2018 were as follows:

Investment Balance	June 30, 2019			December 31, 2018
	(in millions)
SNG	$	1,243		$	1,261
Atlantic Coast Pipeline	101			83
PennEast Pipeline	77			71
Other(*)	88			123
Total	$	1,509		$	1,538

(*)	Decrease primarily relates to the sale of Triton.

Earnings from Equity Method Investments	Three Months Ended June 30, 2019			Three Months Ended June 30, 2018			Six Months Ended June 30, 2019			Six Months Ended June 30, 2018
	(in millions)
SNG	$	32		$	27		$	74		$	66
Atlantic Coast Pipeline	3			1			6			3
PennEast Pipeline	1			1			3			2
Other(*)	(5		)	2			(3		)	3
Total	$	31		$	31		$	80		$	74

(*)	Decrease primarily relates to the sale of Triton.

Triton

On May 29, 2019, Southern Company Gas sold its investment in Triton, a cargo container leasing company that was aggregated into Southern Company Gas' all other segment. This disposition resulted in a pre-tax loss of $6 million and a net after-tax gain of $7 million as a result of reversing a $13 million federal income tax valuation allowance.

SNG

Selected financial information of SNG for the three and six months ended June 30, 2019 and 2018 is as follows:

Income Statement Information	Three Months Ended June 30, 2019			Three Months Ended June 30, 2018			Six Months Ended June 30, 2019			Six Months Ended June 30, 2018
	(in millions)
Revenues	$	155		$	146		$	321		$	306
Operating income	86			60			192			159
Net income	64			54			148			132

(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, 2019 was approximately $1.4 billion (comprised of approximately $854 million at Alabama Power, $550 million at Georgia

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Power, and $40 million at Mississippi Power). In addition, at June 30, 2019, the traditional electric operating companies had approximately $272 million (comprised of approximately $87 million at Alabama Power and $185 million at Georgia Power) of revenue bonds outstanding that were required to be remarketed within the next 12 months. See Note 8 to the financial statements 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, 2019:

	Expires
Company	2019			2020			2022			2024				Total				Unused			Due within One Year
	(in millions)
Southern Company(a)	$	—		$	—		$	—		$	2,000			$	2,000			$	1,999		$	—
Alabama Power	3			500			—			800				1,303				1,303			3
Georgia Power	—			—			—			1,750				1,750				1,736			—
Mississippi Power	—			—			150			—				150				150			—
Southern Power(b)	—			—			—			600				600				561			—
Southern Company Gas(c)	—			—			—			1,750				1,750				1,745			—
Other	—			30			—			—				30				30			30
Southern Company Consolidated	$	3		$	530		$	150		$	6,900			$	7,583			$	7,524		$	33

(a)	Represents the Southern Company parent entity.

(b)	Does not include Southern Power Company's $120 million continuing letter of credit facility for standby letters of credit expiring in 2021, of which $30 million was unused at June 30, 2019. Southern Power's subsidiaries are not parties to its bank credit arrangement.

(c)

Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $1.25 billion of this arrangement. Southern Company Gas' committed credit arrangement also includes $500 million for which Nicor Gas is the borrower and which is restricted for working capital needs of Nicor Gas. Pursuant to this multi-year credit arrangement, the allocations between Southern Company Gas Capital and Nicor Gas may be adjusted.

As reflected in the table above, in May 2019, Southern Company, Alabama Power, Georgia Power, and Southern Power each amended and restated certain of their multi-year credit arrangements, which, among other things, extended the maturity dates to 2024. Southern Power also decreased its borrowing capacity from $750 million to $600 million. In addition, Southern Company Gas Capital, along with Nicor Gas, amended and restated its multi-year credit arrangement to extend the maturity date to 2024 and decrease the aggregate borrowing capacity from $1.9 billion to $1.75 billion. In June 2019, Mississippi Power entered into a new $50 million credit arrangement that matures in 2022 and amended its existing credit arrangements, which, among other things, extended the maturity dates from 2019 to 2022.

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 8 to the financial statements under "Long-term Debt – DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K for additional information regarding Georgia Power's 2014 loan guarantee agreement.

Pursuant to the loan guarantee program established under Title XVII of the Energy Policy Act of 2005 (Title XVII Loan Guarantee Program), Georgia Power and the DOE entered into a loan guarantee agreement in 2014 and the Amended and Restated Loan Guarantee Agreement in March 2019. Under the Amended and Restated Loan Guarantee Agreement, the DOE has agreed to guarantee the obligations of Georgia Power under note purchase agreements among the DOE, Georgia Power, and the FFB and related promissory notes which provide for two multi-advance term loan facilities (FFB Credit Facilities). Under the FFB Credit Facilities, Georgia Power may make term loan borrowings through the FFB in an amount up to approximately $5.130 billion, provided that total

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(UNAUDITED)

aggregate borrowings under the FFB Credit Facilities may not exceed 70% of (i) Eligible Project Costs minus (ii) approximately $1.492 billion (reflecting the amounts received by Georgia Power under the Guarantee Settlement Agreement less the Customer Refunds).

In March 2019, Georgia Power made borrowings under the FFB Credit Facilities in an aggregate principal amount of $835 million at an interest rate of 3.213% through the final maturity date of February 20, 2044. At June 30, 2019, Georgia Power had a total of $3.46 billion of borrowings outstanding under the FFB Credit Facilities.

All borrowings under the FFB Credit Facilities are full recourse to Georgia Power, and Georgia Power is obligated to reimburse the DOE for any payments the DOE is required to make to the FFB under its guarantee. Georgia Power's reimbursement obligations to the DOE are full recourse and secured by a first priority lien on (i) Georgia Power's 45.7% undivided ownership interest in Plant Vogtle Units 3 and 4 (primarily the units under construction, the related real property, and any nuclear fuel loaded in the reactor core) and (ii) Georgia Power's rights and obligations under the principal contracts relating to Plant Vogtle Units 3 and 4. There are no restrictions on Georgia Power's ability to grant liens on other property.

In addition to the conditions described above, future advances are subject to satisfaction of customary conditions, as well as certification of compliance with the requirements of the Title XVII Loan Guarantee Program, including accuracy of project-related representations and warranties, delivery of updated project-related information, and evidence of compliance with the prevailing wage requirements of the Davis-Bacon Act of 1931, as amended, and certification from the DOE's consulting engineer that proceeds of the advances are used to reimburse Eligible Project Costs.

Upon satisfaction of all conditions described above, advances may be requested on a quarterly basis through 2023. The final maturity date for each advance under the FFB Credit Facilities is February 20, 2044. Interest is payable quarterly and principal payments will begin on February 20, 2020. Borrowings under the FFB Credit Facilities will bear interest at the applicable U.S. Treasury rate plus a spread equal to 0.375%.

Under the Amended and Restated 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 occur, the FFB's commitment to make further advances under the FFB Credit Facilities will terminate and Georgia Power will be required to prepay the outstanding principal amount of all borrowings under the FFB Credit Facilities 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 any Westinghouse bankruptcy if Georgia Power does not maintain access to intellectual property rights under the related intellectual property licenses; (ii) termination of the Bechtel Agreement, unless the Vogtle Owners enter into a replacement agreement; (iii) cancellation of Plant Vogtle Units 3 and 4 by the Georgia PSC or by Georgia Power; (iv) failure of the holders of 90% of the ownership interests in Plant Vogtle Units 3 and 4 to vote to continue construction following certain schedule extensions; (v) 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 Facilities; or (vi) loss of or failure to receive necessary regulatory approvals. 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 Facilities. 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 Facilities 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 less the Customer Refunds. Georgia Power also may voluntarily prepay outstanding borrowings under the FFB Credit Facilities. Under the FFB Credit Facilities, any prepayment (whether mandatory or optional) will be made with a make-whole premium or discount, as applicable.

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(UNAUDITED)

In connection with any cancellation of Plant Vogtle Units 3 and 4, the DOE may elect to continue construction of Plant Vogtle Units 3 and 4. In such an event, the DOE will have the right to assume Georgia Power's rights and obligations under the principal agreements relating to Plant Vogtle Units 3 and 4 and to acquire all or a portion of Georgia Power's ownership interest in Plant Vogtle Units 3 and 4.

Financing Activities

The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first six months of 2019:

Company	Senior Note Maturities, Redemptions, and Repurchases				Revenue Bond Issuances and Reofferings of Purchased Bonds				Revenue Bond Maturities, Redemptions, and Repurchases				Other Long-Term Debt Issuances				Other Long-Term Debt Redemptions and Maturities(a)
	(in millions)
Southern Company(b)	$	2,100			$	—			$	—			$	—			$	—
Alabama Power	200				—				—				—				—
Georgia Power	—				513				223				835				3
Mississippi Power	—				43				—				—				—
Other	—				—				25				—				9
Southern Company Consolidated	$	2,300			$	556			$	248			$	835			$	12

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

(b)	Represents the Southern Company parent entity.

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. The subsidiaries also used the proceeds for their construction programs.

Southern Company

In January 2019, Southern Company repaid a $250 million short-term uncommitted bank credit arrangement and a $1.5 billion short-term floating rate bank loan.

Also in January 2019, through cash tender offers, Southern Company repurchased and retired approximately $522 million of the $1.0 billion aggregate principal amount outstanding of its 1.85% Senior Notes due July 1, 2019 (1.85% Notes), approximately $180 million of the $350 million aggregate principal amount outstanding of its Series 2014B 2.15% Senior Notes due September 1, 2019 (Series 2014B Notes), and approximately $504 million of the $750 million aggregate principal amount outstanding of its Series 2018A Floating Rate Notes due February 14, 2020 (Series 2018A Notes), for an aggregate purchase price, excluding accrued and unpaid interest, of approximately $1.2 billion. In addition, following the completion of the cash tender offers, in February 2019, Southern Company completed the redemption of all of the Series 2018A Notes, 1.85% Notes, and Series 2014B Notes remaining outstanding.

Georgia Power

In January 2019, Georgia Power redeemed approximately $13 million, $20 million, and $75 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 1992, Eighth Series 1994, and Second Series 1995, respectively.

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(UNAUDITED)

In March 2019, Georgia Power reoffered to the public the following pollution control revenue bonds that previously had been purchased and held by Georgia Power:

•	$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;

•	approximately $105 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

•	$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.

In April 2019, Georgia Power purchased and held the following pollution control revenue bonds. In May 2019, Georgia Power reoffered these pollution control revenue bonds to the public.

•	$55 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Fourth Series 1994;

•	$30 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Fourth Series 1995;

•	$20 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Ninth Series 1994; and

•	$10 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Second Series 1994.

In June 2019, Georgia Power reoffered to the public $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, which had been previously purchased and held by Georgia Power.

Also in June 2019, Georgia Power entered into two short-term floating rate bank loans in aggregate principal amounts of $125 million each, both of which bear interest based on one-month LIBOR.

Mississippi Power

In March 2019, Mississippi Power reoffered to the public $43 million of Mississippi Business Finance Corporation Pollution Control Revenue Refunding Bonds, Series 2002, which previously had been purchased and held by Mississippi Power.

Southern Power

In May 2019, Southern Power repaid at maturity a $100 million aggregate principal amount short-term bank loan.

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 12 to the financial statements 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, 2019		Three Months Ended June 30, 2018		Six Months Ended June 30, 2019		Six Months Ended June 30, 2018
	(in millions)
As reported shares	1,044		1,014		1,041		1,012
Effect of stock-based compensation	8		—		8		5
Diluted shares	1,052		1,014		1,049		1,017

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(UNAUDITED)

There were no stock-based compensation awards that were not included in the diluted earnings per share calculation because they were anti-dilutive for the three and six months ended June 30, 2019 and an immaterial amount of such awards was not included for the six months ended June 30, 2018. For the three months ended June 30, 2018, approximately 5.3 million shares of stock-based compensation awards were not included in the diluted earnings per share calculation because they were anti-dilutive.

(G) INCOME TAXES

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

Current and Deferred Income Taxes

Tax Credit Carryforwards

Southern Company had federal ITC and PTC carryforwards (primarily related to Southern Power) totaling $2.0 billion as of June 30, 2019 compared to $2.4 billion as of December 31, 2018.

The federal ITC and PTC carryforwards begin expiring in 2034 and 2032, respectively, but are expected to be fully utilized by 2023. The estimated tax credit utilization reflects the projected taxable gains on the various sale transactions describe in Note (K) and could be further delayed by numerous factors, including the acquisition of additional renewable projects, the purchase of rights to additional PTCs of Plant Vogtle Units 3 and 4 pursuant to certain joint ownership agreements, and changes in taxable income projections. See Note (B) and Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Nuclear Construction" for additional information regarding Plant Vogtle Units 3 and 4.

Effective Tax Rate

Details of significant changes in the effective tax rate for the applicable registrants are provided herein.

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 flowback of excess deferred income taxes at the regulated utilities, and federal income tax benefits from ITCs and PTCs, primarily at Southern Power.

Southern Company's effective tax rate was 33.5% for the six months ended June 30, 2019 compared to an effective tax benefit rate of (3.2)% for the corresponding period in 2018. The effective tax rate increase was primarily due to the tax impact from the sale of Gulf Power in 2019 and the 2018 charge to earnings related to the construction of Plant Vogtle Units 3 and 4. See Note (K) and Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Nuclear Construction" for additional information.

Georgia Power

Georgia Power's effective tax rate was 21.7% for the six months ended June 30, 2019 compared to a benefit rate of (53.5)% for the corresponding period in 2018. The effective tax rate increase was primarily due to the 2018 charge to earnings related to the construction of Plant Vogtle Units 3 and 4, partially offset by an increase in state ITCs. See Note 2 to the financial statements in Item 8 of the Form 10-K under "Georgia Power – Nuclear Construction" for additional information.

Mississippi Power

Mississippi Power's effective tax rate was 14.0% for the six months ended June 30, 2019 compared to 18.7% for the corresponding period in 2018. The effective tax rate decrease was primarily due to an increase in the flowback of excess deferred income taxes as a result of a settlement agreement reached with wholesale customers under the MRA tariff. See Note (B) under "Mississippi Power" for additional information.

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(UNAUDITED)

Southern Power

Southern Power's effective tax benefit rate was (35.5)% for the six months ended June 30, 2019 compared to (1,386.5)% for the corresponding period in 2018. The effective tax benefit rate decrease was primarily due to reductions of tax benefits from wind PTCs primarily as a result of the 2018 sale of the noncontrolling tax equity interest in SPC Wind and from changes in state apportionment rates following the reorganization of Southern Power's legal entities that own and operate certain solar facilities, partially offset by the net tax benefits from the sale of Plant Nacogdoches in 2019. See Note (K) and Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Power" for additional information.

Southern Company Gas

Southern Company Gas' effective tax rate was 18.0% for the six months ended June 30, 2019 compared to 39.1% for the corresponding period in 2018. This decrease was primarily related to an increase in the flowback of excess deferred income taxes in 2019, primarily at Atlanta Gas Light as previously authorized by the Georgia PSC, and the reversal of a federal tax valuation allowance in connection with Southern Company Gas' sale of its investment in Triton in 2019, as well as the tax impacts of the Southern Company Gas Dispositions in 2018. See Note (E) under "Southern Company Gas" and Notes 2 and 15 to the financial statements under "Southern Company Gas" in Item 8 of the Form 10-K for additional information.

(H) RETIREMENT BENEFITS

The Southern Company system has a qualified defined benefit, trusteed, pension plan covering substantially all employees, with the exception of employees at PowerSecure. The qualified 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 qualified pension plan are anticipated for the year ending December 31, 2019. The Southern Company system also provides certain non-qualified defined benefits for a select group of management and highly compensated employees, which are funded on a cash basis. In addition, the Southern Company system provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The traditional electric operating companies fund other postretirement trusts to the extent required by their respective regulatory commissions. 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.

See Note 11 to the financial statements in Item 8 of the Form 10-K for additional information.

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(UNAUDITED)

On each registrant's condensed statements of income, the service cost component of net periodic benefit costs is included in other operations and maintenance expenses and all other components of net periodic benefit costs are included in other income (expense), net. Components of the net periodic benefit costs for the three and six months ended June 30, 2019 and 2018 are presented in the following tables.

Three Months Ended June 30, 2019	Southern Company				Alabama Power				Georgia Power				Mississippi Power				Southern Power				Southern Company Gas
	(in millions)
Pension Plans
Service cost	$	73			$	17			$	18			$	3			$	1			$	6
Interest cost	123				29				39				5				2				9
Expected return on plan assets	(221		)		(52		)		(73		)		(10		)		(3		)		(15		)
Amortization:
Prior service costs	1				1				1				—				—				—
Regulatory asset	—				—				—				—				—				4
Net (gain)/loss	30				9				11				2				—				—
Net periodic pension cost (income)	$	6			$	4			$	(4	)		$	—			$	—			$	4
Postretirement Benefits
Service cost	$	4			$	1			$	1			$	—			$	—			$	—
Interest cost	17				4				6				1				—				3
Expected return on plan assets	(17		)		(7		)		(6		)		(1		)		—				(1		)
Amortization:
Prior service costs	1				1				—				—				—				—
Regulatory asset	—				—				—				—				—				1
Net (gain)/loss	—				—				—				—				—				(1		)
Net periodic postretirement benefit cost	$	5			$	(1	)		$	1			$	—			$	—			$	2

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(UNAUDITED)

Six Months Ended June 30, 2019	Southern Company				Alabama Power				Georgia Power				Mississippi Power				Southern Power				Southern Company Gas
	(in millions)
Pension Plans
Service cost	$	146			$	34			$	37			$	6			$	3			$	12
Interest cost	246				57				78				11				3				18
Expected return on plan assets	(442		)		(103		)		(146		)		(20		)		(5		)		(30		)
Amortization:
Prior service costs	1				1				1				—				—				(1		)
Regulatory asset	—				—				—				—				—				7
Net (gain)/loss	60				18				22				3				—				1
Net periodic pension cost (income)	$	11			$	7			$	(8	)		$	—			$	1			$	7
Postretirement Benefits
Service cost	$	9			$	2			$	2			$	—			$	—			$	1
Interest cost	34				8				13				2				—				5
Expected return on plan assets	(33		)		(13		)		(12		)		(1		)		—				(3		)
Amortization:
Prior service costs	2				2				—				—				—				—
Regulatory asset	—				—				—				—				—				3
Net (gain)/loss	(1		)		—				—				—				—				(2		)
Net periodic postretirement benefit cost	$	11			$	(1	)		$	3			$	1			$	—			$	4

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(UNAUDITED)

Three Months Ended June 30, 2018	Southern Company				Alabama Power				Georgia Power				Mississippi Power				Southern Power				Southern Company Gas
	(in millions)
Pension Plans
Service cost	$	89			$	20			$	21			$	4			$	2			$	8
Interest cost	116				25				35				5				2				9
Expected return on plan assets	(235		)		(53		)		(74		)		(10		)		(2		)		(17		)
Amortization:
Prior service costs	1				1				1				—				—				—
Regulatory asset	—				—				—				—				—				4
Net (gain)/loss	54				13				17				2				—				3
Net periodic pension cost (income)	$	25			$	6			$	—			$	1			$	2			$	7
Postretirement Benefits
Service cost	$	6			$	2			$	1			$	1			$	—			$	—
Interest cost	18				4				7				1				—				3
Expected return on plan assets	(17		)		(7		)		(7		)		(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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(UNAUDITED)

Six Months Ended June 30, 2018	Southern Company				Alabama Power				Georgia Power				Mississippi Power				Southern Power				Southern Company Gas
	(in millions)
Pension Plans
Service cost	$	179			$	39			$	43			$	8			$	4			$	16
Interest cost	232				50				70				10				3				19
Expected return on plan assets	(471		)		(104		)		(148		)		(20		)		(5		)		(35		)
Amortization:
Prior service costs	2				1				1				—				—				(1		)
Regulatory asset	—				—				—				—				—				7
Net (gain)/loss	107				27				34				5				1				6
Net periodic pension cost (income)	$	49			$	13			$	—			$	3			$	3			$	12
Postretirement Benefits
Service cost	$	12			$	3			$	3			$	1			$	—			$	1
Interest cost	37				8				14				2				—				5
Expected return on plan assets	(34		)		(13		)		(13		)		(1		)		—				(4		)
Amortization:
Prior service costs	3				2				1				—				—				—
Regulatory asset	—				—				—				—				—				3
Net (gain)/loss	7				1				4				—				—				—
Net periodic postretirement benefit cost	$	25			$	1			$	9			$	2			$	—			$	5

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(UNAUDITED)

(I) FAIR VALUE MEASUREMENTS

As of June 30, 2019, 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, 2019:	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)	$	270			$	177			$	12			$	—			$	459
Foreign currency derivatives	—				60				—				—				60
Investments in trusts:(b)(c)
Domestic equity	703				124				—				—				827
Foreign equity	62				206				—				—				268
U.S. Treasury and government agency securities	—				307				—				—				307
Municipal bonds	—				72				—				—				72
Pooled funds – fixed income	—				16				—				—				16
Corporate bonds	23				299				—				—				322
Mortgage and asset backed securities	—				74				—				—				74
Private equity	—				—				—				54				54
Cash and cash equivalents	1				—				—				—				1
Other	27				2				—				—				29
Cash equivalents	841				5				—				—				846
Other investments	9				17				—				—				26
Total	$	1,936			$	1,359			$	12			$	54			$	3,361
Liabilities:
Energy-related derivatives(a)	$	405			$	189			$	22			$	—			$	616
Interest rate derivatives	—				52				—				—				52
Foreign currency derivatives	—				23				—				—				23
Contingent consideration	—				—				21				—				21
Total	$	405			$	264			$	43			$	—			$	712

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(UNAUDITED)

	Fair Value Measurements Using:
As of June 30, 2019:	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)
Alabama Power
Assets:
Energy-related derivatives	$	—			$	6			$	—			$	—			$	6
Nuclear decommissioning trusts:(b)
Domestic equity	456				113				—				—				569
Foreign equity	62				60				—				—				122
U.S. Treasury and government agency securities	—				21				—				—				21
Municipal bonds	—				1				—				—				1
Corporate bonds	23				141				—				—				164
Mortgage and asset backed securities	—				25				—				—				25
Private equity	—				—				—				54				54
Other	7				—				—				—				7
Cash equivalents	430				5				—				—				435
Other investments	—				17				—				—				17
Total	$	978			$	389			$	—			$	54			$	1,421
Liabilities:
Energy-related derivatives	$	—			$	18			$	—			$	—			$	18
Georgia Power
Assets:
Energy-related derivatives	$	—			$	6			$	—			$	—			$	6
Nuclear decommissioning trusts:(b)(c)
Domestic equity	247				1				—				—				248
Foreign equity	—				143				—				—				143
U.S. Treasury and government agency securities	—				286				—				—				286
Municipal bonds	—				71				—				—				71
Corporate bonds	—				158				—				—				158
Mortgage and asset backed securities	—				50				—				—				50
Other	20				2				—				—				22
Total	$	267			$	717			$	—			$	—			$	984
Liabilities:
Energy-related derivatives	$	—			$	43			$	—			$	—			$	43
Interest rate derivatives	—				37				—				—				37
Total	$	—			$	80			$	—			$	—			$	80

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(UNAUDITED)

	Fair Value Measurements Using:
As of June 30, 2019:	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)
Mississippi Power
Assets:
Energy-related derivatives	$	—			$	3			$	—			$	—			$	3
Cash equivalents	170				—				—				—				170
Total	$	170			$	3			$	—			$	—			$	173
Liabilities:
Energy-related derivatives	$	—			$	19			$	—			$	—			$	19
Southern Power
Assets:
Energy-related derivatives	$	—			$	2			$	—			$	—			$	2
Foreign currency derivatives	—				60				—				—				60
Cash equivalents	177				—				—				—				177
Total	$	177			$	62			$	—			$	—			$	239
Liabilities:
Energy-related derivatives	$	—			$	4			$	—			$	—			$	4
Foreign currency derivatives	—				23				—				—				23
Contingent consideration	—				—				21				—				21
Total	$	—			$	27			$	21			$	—			$	48
Southern Company Gas
Assets:
Energy-related derivatives(a)	$	270			$	160			$	12			$	—			$	442
Non-qualified deferred compensation trusts:
Domestic equity	—				10				—				—				10
Foreign equity	—				4				—				—				4
Pooled funds – fixed income	—				16				—				—				16
Cash equivalents	1				—				—				—				1
Total	$	271			$	190			$	12			$	—			$	473
Liabilities:
Energy-related derivatives(a)	$	405			$	105			$	22			$	—			$	532

(a)	Energy-related derivatives exclude cash collateral of $178 million.

(b)	Excludes receivables related to investment income, pending investment sales, payables related to pending investment purchases, and currencies. See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information.

(c)

Includes investment securities pledged to creditors and collateral received and excludes payables related to the securities lending program. As of June 30, 2019, approximately $30 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. See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information.

Southern Company, Alabama Power, and Georgia Power continue to elect the option to fair value investment securities held in the nuclear decommissioning trust funds. The fair value of the funds, including reinvested interest

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and dividends and excluding the funds' expenses, increased (decreased) by the amounts shown in the table below for the three and six months ended June 30, 2019 and 2018. The changes were recorded as a change to the regulatory assets and liabilities related to AROs for Georgia Power and Alabama Power, respectively.

	Three Months Ended June 30, 2019			Three Months Ended June 30, 2018			Six Months Ended June 30, 2019			Six Months Ended June 30, 2018
	(in millions)
Southern Company	$	75		$	14		$	227		$	4
Alabama Power	38			15			125			10
Georgia Power	37			(1		)	102			(6		)

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 (J) for additional information on how these derivatives are used.

For fair value measurements of the investments within the nuclear decommissioning trusts and the non-qualified deferred compensation 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.

The NRC requires licensees of commissioned nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. See Note 6 to the financial statements 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 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.

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As of June 30, 2019, the fair value measurements of private equity investments held in Alabama Power's nuclear decommissioning trusts that are calculated at net asset value per share (or its equivalent) as a practical expedient totaled $54 million and unfunded commitments related to the private equity investments totaled $45 million. Private equity funds include funds-of-funds that invest 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.

As of June 30, 2019, other financial instruments for which the carrying amount did not equal fair value were as follows:

	Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Power			Southern Company Gas(*)
	(in millions)
Long-term debt, including securities due within one year:
Carrying amount	$	42,596		$	7,922		$	10,969		$	1,618		$	5,011		$	5,916
Fair value	45,394			8,717			11,749			1,657			5,261			6,420

(*)	The long-term debt of Southern Company Gas is recorded at amortized cost, including the fair value adjustments at the effective date of the 2016 merger with Southern Company. Southern Company Gas amortizes the fair value adjustments over the lives of the respective bonds.

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, Mississippi Power, Southern Power, and Southern Company Gas.

Commodity Contracts with Level 3 Valuation Inputs

As of June 30, 2019, the fair value of Southern Company Gas' Level 3 physical natural gas forward contracts was $10 million. Since commodity contracts classified as Level 3 typically include a combination of observable and unobservable components, the changes in fair value may include amounts due in part to observable market factors, or changes to assumptions on the unobservable components. The following table includes transfers to Level 3, which represent the fair value of Southern Company Gas' commodity derivative contracts that include a significant unobservable component for the first time during the period.

	Three Months Ended June 30, 2019			Six Months Ended June 30, 2019
	(in millions)
Beginning balance	$	(19	)	$	—
Transfers to Level 3	(3		)	(33		)
Changes in fair value	12			23
Ending balance	$	(10	)	$	(10	)

Changes in fair value of Level 3 instruments represent changes in gains and losses for the periods that are reported on Southern Company Gas' statements of income in natural gas revenues.

The valuation of certain commodity contracts requires the use of certain unobservable inputs. All forward pricing used in the valuation of such contracts is directly based on third-party market data, such as broker quotes and exchange settlements, when that data is available. If third-party market data is not available, then industry standard methodologies are used to develop inputs that maximize the use of relevant observable inputs and minimize the use of unobservable inputs. Observable inputs, including some forward prices used for determining fair value, reflect the best available market information. Unobservable inputs are updated using industry standard techniques such as extrapolation, combining observable forward inputs supplemented by historical market and other relevant data. Level 3 physical natural gas forward contracts include unobservable forward price inputs (ranging from $0.09

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to $1.39 per mmBtu). Forward price increases (decreases) as of June 30, 2019 would have resulted in higher (lower) values on a net basis.

(J) 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 (I) for additional fair value information. In the statements of cash flows, any cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities. Any 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. See Note 1 to the financial statements under "Financial Instruments" in Item 8 of the Form 10-K for additional information.

Energy-Related Derivatives

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 are expected to continue to mitigate price volatility. The traditional electric operating companies (with respect to wholesale generating capacity) and Southern Power have limited exposure to market volatility in 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.

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Energy-related derivative contracts are accounted for under one of three methods:

•

Regulatory Hedges — Energy-related derivative contracts 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 accumulated 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, 2019, the net volume of energy-related derivative contracts for natural gas positions, 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(*)	536		2023		2029
Alabama Power	88		2022		—
Georgia Power	200		2022		—
Mississippi Power	101		2023		—
Southern Power	8		2020		—
Southern Company Gas(*)	139		2021		2029

(*)

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 4.0 billion mmBtu and short natural gas positions of 3.9 billion mmBtu as of June 30, 2019, 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 natural gas due to operational constraints. The maximum expected volume of natural gas subject to such a feature is 25 million mmBtu for Southern Company, which includes 4 million mmBtu for Alabama Power, 8 million mmBtu for Georgia Power, 4 million mmBtu for Mississippi Power, and 9 million mmBtu for Southern Power.

For cash flow hedges of energy-related derivatives, the estimated pre-tax gains (losses) expected to be reclassified from accumulated OCI to earnings for the 12-month period ending June 30, 2020 are immaterial for all registrants.

Interest Rate Derivatives

Southern Company and certain subsidiaries may 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

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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, 2019, 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, 2019
	(in millions)								(in millions)
Cash Flow Hedges of Forecasted Debt
Georgia Power	$	250			3-month LIBOR	2.23%	March 2025		$	(6	)
Georgia Power	250				3-month LIBOR	2.39%	September 2029		(10		)
Georgia Power	250				3-month LIBOR	2.40%	March 2030		(9		)
Georgia Power	250				3-month LIBOR	2.48%	February 2044		(12		)
Fair Value Hedges of Existing Debt
Southern Company(*)	300				2.75%	3-month LIBOR+0.92%	June 2020		(1		)
Southern Company(*)	1,500				2.35%	1-month LIBOR+0.87%	July 2021		(14		)
Georgia Power	200				4.25%	3-month LIBOR+2.46%	December 2019		(1		)
Southern Company Consolidated	$	3,000							$	(53	)

(*)	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 12-month period ending June 30, 2020 are $(18) million for Southern Company and immaterial for all other registrants. Deferred gains and losses related to interest rate derivatives are expected to be amortized into earnings through 2046 for the Southern Company parent entity, 2035 for Alabama Power, 2044 for Georgia Power, 2028 for Mississippi Power, and 2046 for Southern Company Gas.

Foreign Currency Derivatives

Southern Company and certain subsidiaries, including Southern Power, may 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.

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At June 30, 2019, 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, 2019
	(in millions)				(in millions)					(in millions)
Cash Flow Hedges of Existing Debt
Southern Power	$	677		2.95%	€	600		1.00%	June 2022	$	14
Southern Power	564			3.78%	500			1.85%	June 2026	23
Total	$	1,241			€	1,100				$	37

The estimated pre-tax gains (losses) related to Southern Power's foreign currency derivatives expected to be reclassified from accumulated OCI to earnings for the 12-month period ending June 30, 2020 are $(23) million.

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.

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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, 2019						As of December 31, 2018
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	$	7		$	57		$	8		$	23
Other deferred charges and assets/Other deferred credits and liabilities	9			34			9			26
Assets held for sale, current/Liabilities held for sale, current	—			—			—			6
Total derivatives designated as hedging instruments for regulatory purposes	$	16		$	91		$	17		$	55
Derivatives designated as hedging instruments in cash flow and fair value hedges
Energy-related derivatives:
Other current assets/Other current liabilities	$	1		$	7		$	3		$	7
Other deferred charges and assets/Other deferred credits and liabilities	—			1			1			2
Interest rate derivatives:
Other current assets/Other current liabilities	—			50			—			19
Other deferred charges and assets/Other deferred credits and liabilities	—			2			—			30
Foreign currency derivatives:
Other current assets/Other current liabilities	—			23			—			23
Other deferred charges and assets/Other deferred credits and liabilities	60			—			75			—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	61		$	83		$	79		$	81
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets/Other current liabilities	$	286		$	298		$	561		$	575
Other deferred charges and assets/Other deferred credits and liabilities	156			219			180			325
Total derivatives not designated as hedging instruments	$	442		$	517		$	741		$	900
Gross amounts recognized	$	519		$	691		$	837		$	1,036
Gross amounts offset(a)	$	(328	)	$	(506	)	$	(524	)	$	(801	)
Net amounts recognized in the Balance Sheets(b)	$	191		$	185		$	313		$	235

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	As of June 30, 2019						As of December 31, 2018
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	$	4		$	11		$	3		$	4
Other deferred charges and assets/Other deferred credits and liabilities	2			7			3			6
Total derivatives designated as hedging instruments for regulatory purposes	$	6		$	18		$	6		$	10
Gross amounts recognized	$	6		$	18		$	6		$	10
Gross amounts offset	$	(3	)	$	(3	)	$	(4	)	$	(4	)
Net amounts recognized in the Balance Sheets	$	3		$	15		$	2		$	6
Georgia Power
Derivatives designated as hedging instruments for regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities	$	1		$	26		$	2		$	8
Other deferred charges and assets/Other deferred credits and liabilities	5			17			4			13
Total derivatives designated as hedging instruments for regulatory purposes	$	6		$	43		$	6		$	21
Derivatives designated as hedging instruments in cash flow and fair value hedges
Interest rate derivatives:
Other current assets/Other current liabilities	$	—		$	37		$	—		$	2
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	—		$	37		$	—		$	2
Gross amounts recognized	$	6		$	80		$	6		$	23
Gross amounts offset	$	(6	)	$	(6	)	$	(6	)	$	(6	)
Net amounts recognized in the Balance Sheets	$	—		$	74		$	—		$	17

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	As of June 30, 2019						As of December 31, 2018
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	$	1		$	10		$	1		$	3
Other deferred charges and assets/Other deferred credits and liabilities	2			9			2			6
Total derivatives designated as hedging instruments for regulatory purposes	$	3		$	19		$	3		$	9
Gross amounts recognized	$	3		$	19		$	3		$	9
Gross amounts offset	$	(3	)	$	(3	)	$	(2	)	$	(2	)
Net amounts recognized in the Balance Sheets	$	—		$	16		$	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	$	1		$	3		$	3		$	6
Other deferred charges and assets/Other deferred credits and liabilities	—			1			1			2
Foreign currency derivatives:
Other current assets/Other current liabilities	—			23			—			23
Other deferred charges and assets/Other deferred credits and liabilities	60			—			75			—
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	61		$	27		$	79		$	31
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets/Other current liabilities	$	1		$	—		$	—		$	—
Total derivatives not designated as hedging instruments	$	1		$	—		$	—		$	—
Gross amounts recognized	$	62		$	27		$	79		$	31
Gross amounts offset	$	(1	)	$	(1	)	$	(3	)	$	(3	)
Net amounts recognized in the Balance Sheets	$	61		$	26		$	76		$	28

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	As of June 30, 2019						As of December 31, 2018
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	$	1		$	10		$	2		$	8
Other deferred charges and assets/Other deferred credits and liabilities	—			1			—			1
Total derivatives designated as hedging instruments for regulatory purposes	$	1		$	11		$	2		$	9
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	$	—		$	4		$	—		$	1
Total derivatives designated as hedging instruments in cash flow and fair value hedges	$	—		$	4		$	—		$	1
Derivatives not designated as hedging instruments
Energy-related derivatives:
Assets from risk management activities/Liabilities from risk management activities-current	$	285		$	298		$	559		$	574
Other deferred charges and assets/Other deferred credits and liabilities	156			219			180			325
Total derivatives not designated as hedging instruments	$	441		$	517		$	739		$	899
Gross amounts of recognized	$	442		$	532		$	741		$	909
Gross amounts offset(a)	$	(315	)	$	(493	)	$	(508	)	$	(785	)
Net amounts recognized in the Balance Sheets(b)	$	127		$	39		$	233		$	124

(a)	Gross amounts offset include cash collateral held on deposit in broker margin accounts of $178 million and $277 million as of June 30, 2019 and December 31, 2018, respectively.

(b)	Net amounts of derivative instruments outstanding exclude premium and intrinsic value associated with weather derivatives of $8 million as of December 31, 2018.

At June 30, 2019 and December 31, 2018, 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, 2019
Derivative Category and Balance Sheet Location	Southern Company(*)			Alabama Power			Georgia Power			Mississippi Power			Southern Company Gas(*)
	(in millions)
Energy-related derivatives:
Other regulatory assets, current	$	(48	)	$	(11	)	$	(25	)	$	(10	)	$	(2	)
Other regulatory assets, deferred	(23		)	(5		)	(12		)	(6		)	—
Other regulatory liabilities, current	6			3			—			—			3
Total energy-related derivative gains (losses)	$	(65	)	$	(13	)	$	(37	)	$	(16	)	$	1

(*)	Fair value gains and losses recorded in regulatory assets and liabilities include cash collateral held on deposit in broker margin accounts of $12 million at June 30, 2019.

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Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at December 31, 2018
Derivative Category and Balance Sheet Location	Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Company Gas
	(in millions)
Energy-related derivatives:
Other regulatory assets, current	$	(19	)	$	(3	)	$	(6	)	$	(2	)	$	(8	)
Other regulatory assets, deferred	(16		)	(3		)	(9		)	(4		)	—
Assets held for sale, current	(6		)	—			—			—			—
Other regulatory liabilities, current	1			—			—			—			1
Total energy-related derivative gains (losses)	$	(40	)	$	(6	)	$	(15	)	$	(6	)	$	(7	)

For the three and six months ended June 30, 2019 and 2018, 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,
	2019			2018			2019			2018
	(in millions)						(in millions)
Southern Company
Energy-related derivatives	$	(6	)	$	—		$	(6	)	$	12
Interest rate derivatives	(37		)	—			(37		)	(2		)
Foreign currency derivatives	(1		)	(73		)	(39		)	(21		)
Total	$	(44	)	$	(73	)	$	(82	)	$	(11	)
Georgia Power
Interest rate derivatives	$	(37	)	$	—		$	(37	)	$	—
Total	$	(37	)	$	—		$	(37	)	$	—
Southern Power
Energy-related derivatives	$	(2	)	$	(1	)	$	(2	)	$	10
Foreign currency derivatives	(1		)	(73		)	(39		)	(21		)
Total	$	(3	)	$	(74	)	$	(41	)	$	(11	)

For the three and six months ended June 30, 2019 and 2018, 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.

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For the three and six months ended June 30, 2019 and 2018, 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,
		2019			2018			2019			2018
		(in millions)						(in millions)
	Southern Company
	Total depreciation and amortization	$	755		$	783		$	1,506		$	1,552
	Gain (loss) on energy-related cash flow hedges(a)	(1		)	1			(4		)	2
	Total interest expense, net of amounts capitalized	(429		)	(470		)	(859		)	(928		)
	Gain (loss) on interest rate cash flow hedges(a)	(5		)	(6		)	(9		)	(11		)
	Gain (loss) on foreign currency cash flow hedges(a)	(6		)	(7		)	(12		)	(12		)
	Gain (loss) on interest rate fair value hedges(b)	19			(7		)	33			(31		)
	Total other income (expense), net	99			78			176			138
	Gain (loss) on foreign currency cash flow hedges(a)(c)	16			(73		)	(8		)	(37		)
	Southern Power
	Total depreciation and amortization	$	119		$	125		$	237		$	240
	Gain (loss) on energy-related cash flow hedges(a)	(1		)	1			(4		)	2
	Total interest expense, net of amounts capitalized	(41		)	(46		)	(84		)	(93		)
	Gain (loss) on foreign currency cash flow hedges(a)	(6		)	(7		)	(12		)	(12		)
	Total other income (expense), net	40			2			41			5
	Gain (loss) on foreign currency cash flow hedges(a)(c)	16			(73		)	(8		)	(37		)

(a)	Reclassified from accumulated OCI into earnings.

(b)	For fair value hedges, changes in the fair value of the derivative contracts are generally 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, 2019 and 2018, the pre-tax effects of cash flow and fair value hedge accounting on income for energy-related derivatives and interest rate derivatives were immaterial for the traditional electric operating companies and Southern Company Gas.

As of June 30, 2019 and December 31, 2018, 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, 2019			As of December 31, 2018				As of June 30, 2019			As of December 31, 2018
	(in millions)							(in millions)
Southern Company
Securities due within one year	$	(499	)	$	(498	)		$	1		$	2
Long-term debt	(2,087		)	(2,052		)		7			41
Georgia Power
Securities due within one year	$	(499	)	$	(498	)		$	1		$	2

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For the three and six months ended June 30, 2019 and 2018, the pre-tax effects of energy-related derivatives not designated as hedging instruments on the statements of income of Southern Company and Southern Company Gas 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	2019			2018				2019			2018
		(in millions)							(in millions)
Southern Company
Energy-related derivatives:	Natural gas revenues(*)	$	50		$	(28	)		$	83		$	(43	)
	Cost of natural gas	(5		)	2				3			4
Total derivatives in non-designated hedging relationships		$	45		$	(26	)		$	86		$	(39	)
Southern Company Gas
Energy-related derivatives:	Natural gas revenues(*)	$	50		$	(28	)		$	83		$	(43	)
	Cost of natural gas	(5		)	2				3			4
Total derivatives in non-designated hedging relationships		$	45		$	(26	)		$	86		$	(39	)

(*)	Excludes immaterial gains (losses) recorded in natural gas revenues associated with weather derivatives for all periods presented.

For the three and six months ended June 30, 2019 and 2018, 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, 2019, the registrants had no collateral posted with derivative counterparties to satisfy these arrangements.

For the registrants with interest rate derivatives at June 30, 2019, 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, 2019, 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. Following the sale of Gulf Power to NextEra Energy, Gulf Power is continuing to participate in the Southern Company power pool for a defined transition period that, subject to certain potential adjustments, is scheduled to end on January 1, 2024.

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, 2019, cash

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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, 2019, cash collateral held on deposit in broker margin accounts was $178 million.

The registrants are exposed to losses related to financial instruments in the event of counterparties' nonperformance. The registrants 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. The registrants have also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate their exposure to counterparty credit risk. Prior to entering into a physical transaction, Southern Company Gas assigns physical wholesale counterparties an internal credit rating and credit limit based on the counterparties' Moody's, S&P, and Fitch Ratings Inc. ratings, commercially available credit reports, and audited financial statements. 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.

The registrants do not anticipate a material adverse effect on their respective financial statements as a result of counterparty nonperformance.

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(K) ACQUISITIONS AND DISPOSITIONS

See Note 15 to the financial statements in Item 8 of the Form 10-K for additional information.

Southern Company

On January 1, 2019, Southern Company completed the sale of all of the capital stock of Gulf Power to 700 Universe, LLC, a wholly-owned subsidiary of NextEra Energy, for an aggregate cash purchase price of approximately $5.8 billion (less $1.3 billion of indebtedness assumed), subject to customary working capital adjustments. The preliminary gain associated with the sale of Gulf Power totaled $2.5 billion pre-tax ($1.3 billion after tax). The assets and liabilities of Gulf Power were classified as assets held for sale and liabilities held for sale on Southern Company's balance sheet as of December 31, 2018.

On July 22, 2019, PowerSecure completed the sale of its utility infrastructure services business unit for approximately $71 million, subject to customary working capital adjustments. The related assets and liabilities were classified as held for sale on Southern Company's balance sheet as of June 30, 2019. In contemplation of this sale, a goodwill impairment charge of $32 million was recorded in the second quarter 2019.

See "Assets Held for Sale" herein for additional information.

Southern Power

Construction Projects

During the six months ended June 30, 2019, Southern Power completed construction of and placed in service the 385-MW Plant Mankato expansion and continued construction of two other projects as described in the table below. Total aggregate construction costs, excluding acquisition costs, are expected to be between $405 million and $450 million for the Wildhorse Mountain and Reading facilities. At June 30, 2019, total costs of construction incurred for these projects were $186 million and are included in CWIP. 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 Completed During the Six Months Ended June 30, 2019
Mankato expansion(a)	Natural Gas	385	Mankato, MN	May 2019	20 years
Projects Under Construction as of June 30, 2019
Wildhorse Mountain(b)	Wind	100	Pushmataha County, OK	Fourth quarter 2019	20 years
Reading(c)	Wind	200	Osage and Lyon Counties, KS	Second quarter 2020	12 years

(a)

In November 2018, Southern Power entered into an agreement to sell all of its equity interests in Plant Mankato, including this expansion that was completed during May 2019. This transaction is subject to state commission approvals and is expected to close in fall 2019. The expansion unit started providing energy under a PPA with Northern States Power on June 1, 2019. See "Sales of Natural Gas and Biomass Plants" below.

(b)	In May 2018, Southern Power purchased 100% of the Wildhorse Mountain facility. Southern Power entered into a tax equity partnership in June 2019 with funding of tax equity amounts expected to occur upon commercial operation.

(c)	In August 2018, Southern Power purchased 100% of the membership interests of the Reading facility from the joint development arrangement with Renewable Energy Systems Americas, Inc. Southern Power may enter into a tax equity partnership, in which case it would then own 100% of the class B membership interests.

Development Projects

Southern Power continues to evaluate and refine the deployment of wind turbine equipment purchased in 2016 and 2017 to potential joint development and construction projects as well as the amount of MW capacity to be

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constructed. During the six months ended June 30, 2019, certain wind turbine equipment was sold, resulting in a gain on the sale of approximately $14 million.

On June 14, 2019, Southern Power entered into an agreement with Bloom Energy to acquire a majority interest in its affiliate DSGP, which owns and operates fuel cell generation facilities in Delaware, for a total amount not to exceed $173 million. In June 2019, Southern Power, through an affiliate, contributed a total of $116 million in exchange for Class B membership interests in DSGP, with the remainder expected to be contributed by the end of 2019. FERC approval of the transfer of the facilities is expected to occur in the third quarter 2019; however, the ultimate outcome of this matter cannot be determined at this time.

Sales of Natural Gas and Biomass Plants

On June 13, 2019, Southern Power completed the sale of its equity interests in Nacogdoches Power, LLC, the owner of an approximately 115-MW biomass facility located in Nacogdoches County, Texas, to Austin Energy, for an aggregate cash purchase price of approximately $461 million, including working capital adjustments. This sale resulted in an $88 million after-tax gain.

On May 4, 2019, Southern Power achieved commercial operation of the 385-MW natural gas expansion unit at Plant Mankato and started providing energy under a PPA with Northern States Power on June 1, 2019. The sale of Plant Mankato to Northern States Power remains subject to Minnesota and North Dakota state commission approvals and is expected to close in fall 2019. If these state commission approvals are not obtained by October 1, 2019, either party has the option to terminate the sale, which, if elected, would result in the payment of a $15 million termination fee by Northern States Power to Southern Power. The ultimate outcome of this matter cannot be determined at this time. The assets and liabilities of Plant Mankato 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, 2019 and December 31, 2018. See "Assets Held for Sale" herein for additional information.

Assets Subject to Lien

Under the terms of the PPAs for Plant Mankato, approximately $545 million of assets, primarily related to property, plant, and equipment, are subject to lien at June 30, 2019.

Assets Held for Sale

As discussed above, Southern Company and Southern Power each have assets and liabilities held for sale on their balance sheets at June 30, 2019 and December 31, 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 November 2018 and April 2019 for Plant Mankato and Plant Nacogdoches, respectively, Southern Power ceased recognizing depreciation and amortization on the long-lived assets to be sold.

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The following table provides Southern Company's and Southern Power's major classes of assets and liabilities classified as held for sale at June 30, 2019 and December 31, 2018:

	Southern Company			Southern Power
	(in millions)
At June 30, 2019
Assets Held for Sale:
Current assets	$	58		$	10
Total property, plant, and equipment	588			559
Goodwill and other intangible assets	51			40
Other non-current assets	46			—
Total Assets Held for Sale	$	743		$	609
Liabilities Held for Sale:
Current liabilities	$	36		$	10
Other non-current liabilities	39			—
Total Liabilities Held for Sale	$	75		$	10
At December 31, 2018
Assets Held for Sale:
Current assets	$	393		$	8
Total property, plant, and equipment	4,583			536
Other intangible assets	40			40
Other non-current assets	727			—
Total Assets Held for Sale	$	5,743		$	584
Liabilities Held for Sale:
Current liabilities	$	425		$	15
Long-term debt	1,286			—
Accumulated deferred income taxes	618			—
Other non-current liabilities	932			—
Total Liabilities Held for Sale	$	3,261		$	15

Southern Company and Southern Power each concluded that the sale of their 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 the assets related to the sales have been classified as discontinued operations for any of the periods presented.

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Gulf Power and Southern Power's equity interests in Plant Oleander and Plant Stanton Unit A (together, the Florida Plants) and Plant Nacogdoches represented 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, 2019 and 2018 is presented below:

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2019			2018			2019			2018
	(in millions)
Earnings before income taxes:
Gulf Power	$	—		$	31		$	—		$	87
Southern Power's Florida Plants	$	—		$	14		$	—		$	24
Southern Power's Plant Nacogdoches(*)	$	9		$	7		$	16		$	13

(*)	Earnings before income taxes for Plant Nacogdoches for the three and six months ended June 30, 2019 represents the beginning of the corresponding period through June 13, 2019 (the divestiture date).

(L) LEASES

On January 1, 2019, the registrants adopted the provisions of FASB ASC Topic 842 (as amended), Leases (ASC 842), which require lessees to recognize leases with a term of greater than 12 months on the balance sheet as lease obligations, representing the discounted future fixed payments due, along with right-of-use (ROU) assets that will be amortized over the term of each lease.

The registrants elected the transition methodology provided by ASC 842, whereby the applicable requirements are applied on a prospective basis as of the adoption date of January 1, 2019, without restating prior periods. The registrants also elected the package of practical expedients provided by ASC 842 that allows prior determinations of whether existing contracts are, or contain, leases and the classification of existing leases to continue without reassessment. Additionally, the registrants applied the use-of-hindsight practical expedient in determining lease terms as of the date of adoption and elected the practical expedient that allows existing land easements not previously accounted for as leases not to be reassessed.

Lessee

As lessee, the registrants lease certain electric generating units (including renewable energy facilities), real estate/land, communication towers, railcars, and other equipment and vehicles. The major categories of lease obligations are as follows:

	As of June 30, 2019
	Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Power			Southern Company Gas
	(in millions)
Electric generating units	$	1,072		$	150		$	1,580		$	—		$	—		$	—
Real estate/land	800			4			62			2			395			81
Communication towers	147			1			3			—			—			13
Railcars	54			25			27			3			—			—
Other	145			10			14			2			—			—
Total	$	2,218		$	190		$	1,686		$	7		$	395		$	94

Real estate/land leases primarily consist of commercial real estate leases at Southern Company, Georgia Power, and Southern Company Gas and various land leases primarily associated with renewable energy facilities at Southern

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Power. The commercial real estate leases have remaining terms of up to 25 years while the land leases have remaining terms of up to 48 years, including renewal periods.

Communication towers are leased for the installation of equipment to provide cellular phone service to customers and to support the automated meter infrastructure programs at the traditional electric operating companies. Communication tower leases have terms of up to 10 years with options to renew for periods up to 20 years.

While renewal options exist in many of the leases, other than for land leases associated with renewable energy facilities, the expected term used in calculating the lease obligation generally reflects only the noncancelable period of the lease as it is not considered reasonably certain that the lease will be extended. The expected term of land leases associated with renewable energy facilities includes renewal periods reasonably certain of exercise resulting in an expected lease term at least equal to the expected life of the renewable energy facilities.

Contracts that Contain a Lease

While not specifically structured as a lease, some of the PPAs at Alabama Power and Georgia Power are deemed to represent a lease of the underlying electric generating units when the terms of the PPA convey the right to control the use of the underlying assets. Amounts recorded for leases of electric generating units are generally based on the amount of scheduled capacity payments due over the remaining term of the affiliate PPA, which varies between four and 18 years. Georgia Power has several PPAs with Southern Power that Georgia Power accounts for as leases with a lease obligation of approximately $660 million at June 30, 2019. The amount paid for energy under these affiliate PPAs reflects a price that would be paid in an arm's-length transaction as those amounts have been reviewed and approved by the Georgia PSC.

Short-term Leases

Leases with an initial term of 12 months or less are not recorded on the balance sheet; the registrants generally recognize lease expense for these leases on a straight-line basis over the lease term.

Residual Value Guarantees

Residual value guarantees exist primarily in railcar leases at Alabama Power and Georgia Power and the amounts probable of being paid under those guarantees are included in the lease payments. All such amounts are immaterial as of June 30, 2019.

Lease and Nonlease Components

For all asset categories, with the exception of electric generating units, gas pipelines, and real estate leases, the registrants combine lease payments and any nonlease components, such as asset maintenance, for purposes of calculating the lease obligation and the right-of-use asset.

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Balance sheet amounts recorded for operating and finance leases are as follows:

	As of June 30, 2019
	Southern  Company(*)			Alabama Power			Georgia Power			Mississippi Power			Southern Power			Southern Company Gas
	(in millions)
Operating Leases
Operating lease ROU assets, net	$	1,907		$	152		$	1,492		$	7		$	370		$	95
Operating lease obligations - current	$	241		$	48		$	140		$	2		$	22		$	15
Operating lease obligations - non current	1,733			137			1,377			5			373			79
Total operating lease obligations	$	1,974		$	185		$	1,517		$	7		$	395		$	94
Finance Leases
Finance lease ROU assets, net	$	237		$	5		$	142		$	—		$	—		$	—
Finance lease obligations - current	$	24		$	1		$	10		$	—		$	—		$	—
Finance lease obligations - noncurrent	220			4			159			—			—			—
Total finance lease obligations	$	244		$	5		$	169		$	—		$	—		$	—

(*)	Includes operating lease ROU assets, net and operating lease obligations classified as held for sale.

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Lease costs for the three and six months ended June 30, 2019, which includes both amounts recognized as operations and maintenance expense and amounts capitalized as part of the cost of another asset, are as follows:

	Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Power			Southern Company Gas
	(in millions)
For the Three Months Ended June 30, 2019
Lease cost
Operating lease cost	$	77		$	13		$	50		$	1		$	7		$	5
Finance lease cost:
Amortization of ROU assets	7			—			4			—			—			—
Interest on lease obligations	3			—			4			—			—			—
Total finance lease cost	10			—			8			—			—			—
Short-term lease costs	13			6			6			—			—			—
Variable lease cost	29			1			25			—			1			—
Sublease income	—			—			—			—			—			—
Total lease cost	$	129		$	20		$	89		$	1		$	8		$	5
For the Six Months Ended June 30, 2019
Lease cost
Operating lease cost	$	147		$	20		$	99		$	1		$	14		$	9
Finance lease cost:
Amortization of ROU assets	14			—			7			—			—			—
Interest on lease obligations	6			—			9			—			—			—
Total finance lease cost	20			—			16			—			—			—
Short-term lease costs	30			11			12			—			—			—
Variable lease cost	48			1			41			—			3			—
Sublease income	—			—			—			—			—			—
Total lease cost	$	245		$	32		$	168		$	1		$	17		$	9

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(UNAUDITED)

Georgia Power has variable lease payments that are based on the amount of energy produced by certain renewable generating facilities subject to PPAs.

Other information with respect to cash and noncash activities related to leases, as well as weighted-average lease terms and discount rates, is as follows:

	For the Six Months Ended June 30, 2019
	Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Power			Southern Company Gas
	(in millions)
Other information
Cash paid for amounts included in the measurements of lease obligations:
Operating cash flows from operating leases	$	129		$	20		$	75		$	1		$	12		$	9
Operating cash flows from finance leases	2			—			10			—			—			—
Financing cash flows from finance leases	16			—			3			—			—			—
ROU assets obtained in exchange for new operating lease obligations	55			5			13			—			—			13
ROU assets obtained in exchange for new finance lease obligations	33			1			28			—			—			—

	As of June 30, 2019
	Southern Company		Alabama Power		Georgia Power		Mississippi Power		Southern Power		Southern Company Gas
Weighted-average remaining lease term in years:
Operating leases	14.0		3.6		10.5		7.0		33.5		9.7
Finance leases	18.3		12.8		11.0		N/A		N/A		N/A
Weighted-average discount rate:
Operating leases	4.53	%	3.33	%	4.46	%	4.06	%	5.68	%	3.73	%
Finance leases	5.05	%	3.67	%	10.69	%	N/A		N/A		N/A

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Maturities of lease liabilities are as follows:

	As of June 30, 2019
	Southern Company			Alabama Power			Georgia Power			Mississippi Power			Southern Power			Southern Company Gas
	(in millions)
Maturity Analysis
Operating leases:
2019 (remaining)	$	178		$	33		$	129		$	1		$	13		$	9
2020	295			53			203			2			22			17
2021	279			52			198			1			23			16
2022	268			52			196			1			23			13
2023	204			4			197			1			24			11
Thereafter	1,661			2			990			2			849			49
Total	2,885			196			1,913			8			954			115
Less: Present value discount	911			11			396			1			559			21
Operating lease obligations	$	1,974		$	185		$	1,517		$	7		$	395		$	94
Finance leases:
2019 (remaining)	$	16		$	—		$	16		$	—		$	—		$	—
2020	33			1			28			—			—			—
2021	27			1			25			—			—			—
2022	23			1			25			—			—			—
2023	18			1			25			—			—			—
Thereafter	266			1			165			—			—			—
Total	383			5			284			—			—			—
Less: Present value discount	139			—			115			—			—			—
Finance lease obligations	$	244		$	5		$	169		$	—		$	—		$	—

Payments made under PPAs at Georgia Power for energy generated from certain renewable energy facilities accounted for as operating and finance leases are considered variable lease costs and are therefore not reflected in the above maturity analysis. As of June 30, 2019, Southern Company and Southern Power have additional operating leases, primarily for land, that have not yet commenced. These operating leases are expected to commence during the remainder of 2019 through 2022, with lease terms of up to 31 years, and have estimated total obligations of $81 million.

For additional information on each registrant's operating lease obligations at December 31, 2018, see Note 9 to the financial statements in Item 8 of the Form 10-K.

Lessor

With the exception of Southern Company Gas, the registrants are each considered lessors in various arrangements that have been determined to contain a lease due to the customer's ability to control the use of the underlying asset owned by the applicable registrant. For the traditional electric operating companies, these arrangements consist of outdoor lighting contracts accounted for as operating leases with initial terms of up to five years, after which the contracts renew on a month-to-month basis at the customer's option. For Mississippi Power, these arrangements also include tolling arrangements related to electric generating units accounted for as sales-type leases with terms of up to 20 years. For Southern Power, these arrangements consist of PPAs related to electric generating units, including renewable energy facilities, accounted for as operating leases with terms of up to 28 years. For Southern Company, these arrangements also include PPAs related to fuel cells accounted for as operating leases with terms of up to 15

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(UNAUDITED)

years. Southern Company Gas is the lessor in operating leases related to gas pipelines with remaining terms of up to 24 years.

Lease income for the three and six months ended June 30, 2019 is as follows:

	Southern Company			Georgia Power			Mississippi Power			Southern Power			Southern Company Gas
	(in millions)
For the Three Months Ended June 30, 2019
Lease income - interest income on sales-type leases	$	2		$	—		$	2		$	—		$	—
Lease income - operating leases	67			19			—			39			9
Variable lease income	115			—			—			125			—
Total lease income	$	184		$	19		$	2		$	164		$	9
For the Six Months Ended June 30, 2019
Lease income - interest income on sales-type leases	$	5		$	—		$	5		$	—		$	—
Lease income - operating leases	139			39			—			80			17
Variable lease income	182			—			—			198			—
Total lease income	$	326		$	39		$	5		$	278		$	17

No profit or loss was recognized by Mississippi Power upon commencement of a sales-type lease during the first quarter 2019.

Lease income for Southern Power is included in wholesale revenues. Lease payments received under tolling arrangements and PPAs consist of either scheduled payments or variable payments based on the amount of energy produced by the underlying electric generating units. Scheduled payments to be received under outdoor lighting contracts, tolling arrangements, and PPAs accounted for as leases are presented in the following maturity analyses.

The undiscounted cash flows to be received under tolling arrangements accounted for as sales-type leases are as follows:

	As of June 30, 2019
	Southern Company			Mississippi Power
	(in millions)
2019 (remaining)	$	7		$	7
2020	14			14
2021	14			14
2022	13			13
2023	12			12
Thereafter	135			135
Total undiscounted cash flows	$	195		$	195
Lease receivable	106			106
Difference between undiscounted cash flows and discounted cash flows	$	89		$	89

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(UNAUDITED)

The undiscounted cash flows to be received under operating leases and contracts accounted for as operating leases (adjusted for intercompany eliminations) are as follows:

	As of June 30, 2019
	Southern Company			Georgia Power			Southern Power			Southern Company Gas
	(in millions)
2019 (remaining)	$	75		$	13		$	52		$	17
2020	125			26			65			35
2021	118			18			66			35
2022	109			8			68			34
2023	103			2			69			34
Thereafter	1,142			—			350			497
Total	$	1,672		$	67		$	670		$	652

Southern Power receives payments for renewable energy under PPAs accounted for as operating leases that are considered contingent rents and are therefore not reflected in the table above. Southern Power allocates revenue to the nonlease components of PPAs based on the stand-alone selling price of capacity and energy. The undiscounted cash flows to be received under outdoor lighting contracts accounted for as operating leases at Alabama Power and Mississippi Power are immaterial.

(M) 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 traditional electric operating companies – Alabama Power, Georgia Power, and Mississippi Power – are vertically integrated utilities providing electric service in three 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 and is involved in several other complementary businesses including gas pipeline investments, wholesale gas services, and gas marketing services.

Southern Company's reportable business segments are the sale of electricity by the 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 $117 million and $204 million for the three and six months ended June 30, 2019, respectively, and $109 million and $192 million for the three and six months ended June 30, 2018, respectively. Revenues from sales of natural gas from Southern Company Gas to the traditional electric operating companies were immaterial for both the three and six months ended June 30, 2019 and 2018. Revenues from sales of natural gas from Southern Company Gas to Southern Power were $16 million and $33 million for the three and six months ended June 30, 2019, respectively, and $22 million and $58 million for the three and six months ended June 30, 2018, 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 solutions, such as distributed energy infrastructure and energy efficiency products and services, to customers, as well as investments in telecommunications and leveraged lease projects. All other inter-segment revenues are not material.

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(UNAUDITED)

Financial data for business segments and products and services for the three and six months ended June 30, 2019 and 2018 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, 2019
Operating revenues	$	3,899		$	510		$	(119	)	$	4,290		$	689		$	186		$	(67	)	$	5,098
Segment net income (loss)(a)(b)(c)(d)	782			174			—			956			106			(154		)	(9		)	899
Six Months Ended June 30, 2019
Operating revenues	$	7,343		$	953		$	(211	)	$	8,085		$	2,163		$	368		$	(106	)	$	10,510
Segment net income (loss)(a)(b)(c)(d)	1,346			230			—			1,576			376			1,041			(11		)	2,982
At June 30, 2019
Goodwill	$	—		$	2		$	—		$	2		$	5,015		$	265		$	—		$	5,282
Total assets	78,314			14,518			(783		)	92,049			20,761			3,343			(1,286		)	114,867
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)(d)	(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)(d)(e)	563			143			—			706			248			(174		)	4			784
At December 31, 2018
Goodwill	$	—		$	2		$	—		$	2		$	5,015		$	298		$	—		$	5,315
Total assets	79,382			14,883			(306		)	93,959			21,448			3,285			(1,778		)	116,914

(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 $4 million ($3 million after tax) and $1.1 billion ($0.8 billion after tax) for the three months ended June 30, 2019 and 2018, respectively, and $6 million ($5 million after tax) and $1.1 billion ($0.8 billion after tax) for the six months ended June 30, 2019 and 2018, respectively. See Note 2 to the financial statements in Item 8 of the Form 10-K and Note (B) under "Georgia Power – Nuclear Construction" and "Mississippi Power – Kemper County Energy Facility" for additional information.

(c)

Segment net income (loss) for the "All Other" column includes the preliminary pre-tax gain associated with the sale of Gulf Power of $2.5 billion ($1.3 billion after tax) for the six months ended June 30, 2019, of which $(15) million ($(11) million after tax) was recorded in the three months ended June 30, 2019, as well as a goodwill impairment charge of $32 million for the three and six months ended June 30, 2019 in contemplation of the sale of one of PowerSecure's business units. See Note (K) under "Southern Company" for additional information.

(d)

Segment net income (loss) for Southern Power includes a $23 million pre-tax gain ($88 million gain after tax) on the sale of Plant Nacogdoches for the three and six months ended June 30, 2019 and 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 sale of Southern Power's Florida Plants. See Note (K) under "Southern Power" and Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Power – Sale of Natural Gas Plants" for additional information.

(e)	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 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company Gas" for additional information.

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(UNAUDITED)

Products and Services

	Electric Utilities' Revenues
	Retail			Wholesale			Other			Total
	(in millions)
Three Months Ended June 30, 2019	$	3,540		$	542		$	208		$	4,290
Three Months Ended June 30, 2018	3,740			616			209			4,565
Six Months Ended June 30, 2019	$	6,623		$	1,041		$	421		$	8,085
Six Months Ended June 30, 2018	7,308			1,239			401			8,948

	Southern Company Gas' Revenues
	Gas Distribution Operations(a)			Gas Marketing Services(b)			Other			Total
	(in millions)
Three Months Ended June 30, 2019	$	563		$	58		$	68		$	689
Three Months Ended June 30, 2018	638			89			3			730
Six Months Ended June 30, 2019	$	1,724		$	287		$	152		$	2,163
Six Months Ended June 30, 2018	1,838			359			172			2,369

(a)	Operating revenues for the three gas distribution operations dispositions were $70 million and $237 million for the three and six months ended June 30, 2018, respectively.

(b)	Operating revenues for Pivotal Home Solutions were $24 million and $55 million for the three and six months ended June 30, 2018, respectively.

Southern Company Gas

Southern Company Gas manages its business through four reportable segments – gas distribution operations, gas pipeline investments, wholesale gas services, and gas marketing services. 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 four states.

Gas pipeline investments consists of joint ventures in natural gas pipeline investments including a 50% interest in SNG, two significant pipeline construction projects, and a 50% joint ownership interest in the Dalton Pipeline. These natural gas pipelines enable the provision of diverse sources of natural gas supplies to the customers of Southern Company Gas.

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 marketing services provides natural gas marketing to end-use customers primarily in Georgia and Illinois through SouthStar Energy Services, LLC.

The all other column includes segments below the quantitative threshold for separate disclosure. This includes Southern Company Gas' storage and fuels operations, its investment in Triton through the completion of its sale on May 29, 2019, and other subsidiaries that fall below the quantitative threshold for separate disclosure. See Note (E) under "Southern Company Gas" for additional information and related disclosures.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)

(UNAUDITED)

Business segment financial data for the three and six months ended June 30, 2019 and 2018 was as follows:

	Gas Distribution Operations(a)			Gas Pipeline Investments			Wholesale Gas Services(b)			Gas Marketing Services(c)(d)			Total			All Other			Eliminations			Consolidated
	(in millions)
Three Months Ended June 30, 2019
Operating revenues	$	568		$	8		$	48		$	58		$	682		$	13		$	(6	)	$	689
Segment net income (loss)	58			25			23			(3		)	103			3			—			106
Six Months Ended June 30, 2019
Operating revenues	$	1,740		$	16		$	134		$	287		$	2,177		$	24		$	(38	)	$	2,163
Segment net income (loss)	191			57			70			58			376			—			—			376
Total assets at June 30, 2019	17,397			1,768			668			1,527			21,360			10,934			(11,533		)	20,761
Three Months Ended June 30, 2018
Operating revenues	$	643		$	8		$	(16	)	$	89		$	724		$	11		$	(5	)	$	730
Segment net income (loss)	68			21			(21		)	(76		)	(8		)	(23		)	—			(31		)
Six Months Ended June 30, 2018
Operating revenues	$	1,856		$	16		$	150		$	359		$	2,381		$	26		$	(38	)	$	2,369
Segment net income (loss)	216			48			83			(63		)	284			(36		)	—			248
Total assets at December 31, 2018	17,266			1,763			1,302			1,587			21,918			11,112			(11,582		)	21,448

(a)	Operating revenues for the three gas distribution operations dispositions were $70 million and $237 million for the three and six months ended June 30, 2018, respectively. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company Gas" for additional information.

(b)	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, 2019	$	1,223		$	63		$	1,286		$	1,238		$	48
Three Months Ended June 30, 2018	1,336			102			1,438			1,454			(16		)
Six Months Ended June 30, 2019	$	3,148		$	151		$	3,299		$	3,165		$	134
Six Months Ended June 30, 2018	3,274			269			3,543			3,393			150

(c)	Operating revenues for Pivotal Home Solutions were $24 million and $55 million for the three and six months ended June 30, 2018, respectively. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company Gas" for additional information on the sale of Pivotal Home Solutions.

(d)

Segment net income (loss) 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 related to the sale of Pivotal Home Solutions. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company Gas" for additional information.

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PART II — OTHER INFORMATION

Item 1. Legal Proceedings.

See the Notes to the Condensed Financial Statements herein for information regarding certain legal and administrative proceedings in which the registrants are involved.

Item 1A. Risk Factors.

See RISK FACTORS in Item 1A of the Form 10-K for a discussion of the risk factors of the registrants. There have been no material changes to these risk factors from those previously disclosed in the Form 10-K.

Item 6.    Exhibits.

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 Power
		(e)1	-	Membership Interest Purchase Agreement, dated as of April 17, 2019, by and between Southern Power and The City of Austin d/b/a Austin Energy. (Designated in Form 8-K dated June 13, 2019, File No. 001-37803, as Exhibit 2.1.)
		(e)2	-	Letter Agreement, dated as of May 24, 2019, by and between Southern Power and The City of Austin d/b/a Austin Energy. (Designated in Form 8-K dated June 13, 2019, File No. 001-37803, as Exhibit 2.2.)
		(3) Articles of Incorporation and By-Laws
		Mississippi Power
	*	(d)	-	By-laws of Mississippi Power as amended.
		Southern Company Gas
	*	(e)	-	By-laws of Southern Company Gas as amended.
		(24) Power of Attorney and Resolutions
		Southern Company
		(a)	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2018, File No. 1-3526 as Exhibit 24(a)1.)
		Alabama Power
		(b)	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2018, File No. 1-3164 as Exhibit 24(b).)
		Georgia Power
		(c)	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2018, File No. 1-6468 as Exhibit 24(c).)
		Mississippi Power
		(d)	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2018, File No. 001-11229 as Exhibit 24(d).)

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		Southern Power
		(e)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2018, File No. 001-37803 as Exhibit 24(e)1.)
		Southern Company Gas
		(f)1	-	Power of Attorney and resolution. (Designated in the Form 10-K for the year ended December 31, 2018, File No. 1-14174 as Exhibit 24(f)1.)
		(f)2	-	Power of Attorney of Daniel S. Tucker. (Designated in the Form 10-K for the year ended December 31, 2018, File No. 1-14174 as Exhibit 24(f)2.)
		(31) Section 302 Certifications
		Southern Company
	*	(a)1	-	Certificate of Southern Company's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
	*	(a)2	-	Certificate of Southern Company's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
		Alabama Power
	*	(b)1	-	Certificate of Alabama Power's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
	*	(b)2	-	Certificate of Alabama Power's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
		Georgia Power
	*	(c)1	-	Certificate of Georgia Power's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
	*	(c)2	-	Certificate of Georgia Power's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
		Mississippi Power
	*	(d)1	-	Certificate of Mississippi Power's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
	*	(d)2	-	Certificate of Mississippi Power's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
		Southern Power
	*	(e)1	-	Certificate of Southern Power Company's Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
	*	(e)2	-	Certificate of Southern Power Company's Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
		Southern Company Gas
	*	(f)1	-	Certificate of Southern Company Gas' Chief Executive Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.
	*	(f)2	-	Certificate of Southern Company Gas' Chief Financial Officer required by Section 302 of the Sarbanes-Oxley Act of 2002.

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		(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.
		Mississippi Power
	*	(d)	-	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
	*	(e)	-	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
	*	(f)	-	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 – The instance document does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL 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

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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: July 30, 2019

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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: July 30, 2019

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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		David P. Poroch
		Executive Vice President, Chief Financial Officer, Treasurer, and Comptroller
		(Principal Financial Officer)
By		/s/ Melissa K. Caen
		(Melissa K. Caen, Attorney-in-fact)

Date: July 30, 2019

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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: July 30, 2019

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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 and Chief Executive Officer
		(Principal Executive Officer)
By		Elliott L. Spencer
		Senior Vice President, Chief Financial Officer, and Treasurer
		(Principal Financial Officer)
By		/s/ Melissa K. Caen
		(Melissa K. Caen, Attorney-in-fact)

Date: July 30, 2019

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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		Daniel S. Tucker
		Executive Vice President, Chief Financial Officer, and Treasurer
		(Principal Financial Officer)
By		/s/ Melissa K. Caen
		(Melissa K. Caen, Attorney-in-fact)

Date: July 30, 2019

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