Table of Contents

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 10-Q
þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2018March 31, 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
(A Delaware Corporation)
30 Ivan Allen Jr. Boulevard, N.W.
Atlanta, Georgia 30308
(404) 506-5000
 58-0690070
     
1-3164 
Alabama Power Company
(An Alabama Corporation)
600 North 18th Street
Birmingham, Alabama 35203
(205) 257-1000
 63-0004250
     
1-6468 
Georgia Power Company
(A Georgia Corporation)
241 Ralph McGill Boulevard, N.E.
Atlanta, Georgia 30308
(404) 506-6526
 58-0257110
     
001-31737
Gulf Power Company
(A Florida Corporation)
One Energy Place
Pensacola, Florida 32520
(850) 444-6111
59-0276810
001-11229 
Mississippi Power Company
(A Mississippi Corporation)
2992 West Beach Boulevard
Gulfport, Mississippi 39501
(228) 864-1211
 64-0205820
     
001-37803 
Southern Power Company
(A Delaware Corporation)
30 Ivan Allen Jr. Boulevard, N.W.
Atlanta, Georgia 30308
(404) 506-5000
 58-2598670
     
1-14174 
Southern Company Gas
(A Georgia Corporation)
Ten Peachtree Place, N.E.
Atlanta, Georgia 30309
(404) 584-4000
 58-2210952



Table of Contents

Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes þ No ¨
Indicate by check mark whether the registrants have submitted electronically and posted on their corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrants were required to submit and post such files). Yes þ No ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act. (Check one):
Registrant 
Large
Accelerated
Filer
 
Accelerated
Filer
 
Non-
accelerated
Filer
 
Smaller
Reporting
Company
 
Emerging
Growth
Company
The Southern Company X        
Alabama Power Company     X    
Georgia Power CompanyX
Gulf Power Company     X    
Mississippi Power Company     X    
Southern Power Company     X    
Southern Company Gas     X    
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No þ (Response applicable to all registrants.)
 
Registrant 
Description of
Common Stock
 Shares Outstanding at June 30, 2018March 31, 2019
The Southern Company Par Value $5 Per Share 1,014,136,0831,040,295,732
Alabama Power Company Par Value $40 Per Share 30,537,500
Georgia Power Company Without Par Value 9,261,500
Gulf Power CompanyWithout Par Value7,392,717
Mississippi Power Company Without Par Value 1,121,000
Southern Power Company Par Value $0.01 Per Share 1,000
Southern Company Gas Par Value $0.01 Per Share 100
This combined Form 10-Q is separately filed by The Southern Company, Alabama Power Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company, Southern Power Company, and Southern Company Gas. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Each registrant makes no representation as to information relating to the other registrants.

2

INDEX TO QUARTERLY REPORT ON FORM 10-Q
June 30, 2018March 31, 2019


  
Page
Number
   
   
 PART I—FINANCIAL INFORMATION 
Item 1.Financial Statements (Unaudited) 
Item 2.Management's Discussion and Analysis of Financial Condition and Results of Operations 
  
 
 
 
 
 
  
 
 
 
 
 
  
 
 
 
 
 
  
 
 
 
 
 
  
 
 
 
 
 

3

INDEX TO QUARTERLY REPORT ON FORM 10-Q
June 30, 2018March 31, 2019


  Page
Number
 PART I—FINANCIAL INFORMATION (CONTINUED) 
  
 
 
 
 
 
 
Item 3.
Item 4.
   
 PART II—OTHER INFORMATION 
Item 1.
Item 1A.
Item 2.Unregistered Sales of Equity Securities and Use of ProceedsInapplicable
Item 3.Defaults Upon Senior SecuritiesInapplicable
Item 4.Mine Safety DisclosuresInapplicable
Item 5.Other InformationInapplicable
Item 6.
 

4

Table of Contents

DEFINITIONS

TermMeaning
2013 ARPAlternative Rate Plan approved by the Georgia PSC in 2013 for Georgia Power for the years 2014 through 2016 and subsequently extended through 2019
AFUDCAllowance for funds used during construction
Alabama PowerAlabama Power Company
Amended and Restated Loan Guarantee AgreementLoan 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
AROAsset retirement obligation
ASCAccounting Standards Codification
ASUAccounting Standards Update
Atlanta Gas LightAtlanta Gas Light Company, a wholly-owned subsidiary of Southern Company Gas
Atlantic Coast PipelineAtlantic Coast Pipeline, LLC, a joint venture to construct and operate a natural gas pipeline in which Southern Company Gas has a 5% ownership interest
BechtelBechtel Power Corporation, the primary contractor for the remaining construction activities for Plant Vogtle Units 3 and 4
Bechtel AgreementThe October 23, 2017 construction completion agreement between the Vogtle Owners and Bechtel
CCRCoal combustion residuals
Chattanooga GasChattanooga Gas Company, a wholly-owned subsidiary of Southern Company Gas
CO2
Carbon dioxide
CODCommercial operation date
Contractor Settlement AgreementThe 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 EnergyElectric cooperative in Mississippi
CPCNCertificate of public convenience and necessity
Customer RefundsRefunds to be issued to Georgia Power customers no later than the end of the third quarterin 2018 as ordered by the Georgia PSC related to the Guarantee Settlement Agreement
CWIPConstruction work in progress
DaltonCity 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 PipelineA pipeline facility in Georgia in which Southern Company Gas has a 50% undivided ownership interest of Southern Company Gas in a pipeline facility in Georgia
DOEU.S. Department of Energy
ECO PlanMississippi Power's environmental compliance overview plan
Eligible Project CostsCertain 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
EPAU.S. Environmental Protection Agency
EPC ContractorWestinghouse and its affiliate, WECTEC Global Project Services Inc.; the former engineering, procurement, and construction contractor for Plant Vogtle Units 3 and 4
FASBFinancial Accounting Standards Board
FERCFederal Energy Regulatory Commission
FFBFederal Financing Bank
FitchFitch Ratings, Inc.
Form 10-KAnnual Report on Form 10-K of Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Southern Power, and Southern Company Gas for the year ended December 31, 2017,2018, as applicable
GAAPU.S. generally accepted accounting principles

5

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DEFINITIONS
(continued)

TermMeaning
Georgia PowerGeorgia Power Company
GHGGreenhouse gas
Guarantee Settlement AgreementThe June 9, 2017 settlement agreement between the Vogtle Owners and Toshiba related to certain payment obligations of the EPC Contractor guaranteed by Toshiba Guarantee
Gulf PowerGulf Power Company, until January 1, 2019, a subsidiary of Southern Company
Heating Degree DaysA measure of weather, calculated when the average daily temperatures are less than 65 degrees Fahrenheit
Horizon PipelineHeating SeasonHorizon PipelineThe period from November through March when Southern Company LLCGas' natural gas usage and operating revenues are generally higher
HLBVHypothetical liquidation at book value
IGCCIntegrated coal gasification combined cycle, the technology originally approved for Mississippi Power's Kemper County energy facility (Plant Ratcliffe)
IICIntercompany interchange contract

DEFINITIONS
(continued)
TermMeaningInterchange Contract
Illinois CommissionIllinois Commerce Commission
Interim Assessment AgreementITAACAgreement entered intoInspections, Tests, Analyses, and Acceptance Criteria, standards established by the Vogtle Owners and the EPC Contractor to allow construction to continue after the EPC Contractor's bankruptcy filing
IRSInternal Revenue ServiceNRC
ITCInvestment tax credit
JEAJacksonville Electric Authority
KWHKilowatt-hour
LIBORLondon Interbank Offered Rate
LIFOLast-in, first-out
LNGLiquefied natural gas
Loan Guarantee AgreementLoan guarantee agreement entered into by Georgia Power with the DOE in 2014, under which the proceeds of borrowings may be used to reimburse Georgia Power for Eligible Project Costs incurred in connection with its construction of Plant Vogtle Units 3 and 4
LOCOMLower of weighted average cost or current market price
LTSALong-term service agreement
MEAGMunicipal Electric Authority of Georgia
MergerThe merger, effective July 1, 2016, of a wholly-owned, direct subsidiary of Southern Company with and into Southern Company Gas, with Southern Company Gas continuing as the surviving corporation
Mississippi PowerMississippi Power Company
mmBtuMillion British thermal units
Moody'sMoody's Investors Service, Inc.
MRAMunicipal and Rural Associations
MWMegawatt
natural gas distribution utilitiesSouthern Company Gas' natural gas distribution utilities (Nicor Gas, Atlanta Gas Light, Virginia Natural Gas, Elizabethtown Gas, Florida City Gas, Chattanooga Gas, Company, and Elkton Gas as of June 30, 2018) (Nicor Gas, Atlanta Gas Light, Virginia Natural Gas, and Chattanooga Gas Company as of July 29, 2018)
NCCRGeorgia Power's Nuclear Construction Cost Recovery
New Jersey BPUNew Jersey Board of Public Utilities
NextEra EnergyNextEra Energy, Inc.
Nicor GasNorthern Illinois Gas Company, a wholly-owned subsidiary of Southern Company Gas
NRCU.S. Nuclear Regulatory Commission
NYMEXNew York Mercantile Exchange, Inc.
OATTOpen access transmission tariff
OCIOther comprehensive income
PennEast PipelinePennEast Pipeline Company, LLC, a joint venture to construct and operate a natural gas pipeline in which Southern Company Gas has a 20% ownership interest
PEPMississippi Power's Performance Evaluation Plan
Pivotal Home SolutionsNicor Energy Services Company, until June 4, 2018 a wholly-owned subsidiary of Southern Company Gas, doing business as Pivotal Home Solutions

6

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DEFINITIONS
(continued)

TermMeaning
Pivotal Utility HoldingsPivotal 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
PowerSecurePowerSecure, Inc.
power poolThe 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
PPAPower 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
PSCPublic Service Commission

DEFINITIONS
(continued)
TermMeaning
PTCProduction tax credit
Rate CNPAlabama Power's Rate Certificated New Plant
Rate CNP ComplianceAlabama Power's Rate Certificated New Plant Compliance
Rate CNP PPAAlabama Power's Rate Certificated New Plant Power Purchase Agreement
Rate ECRAlabama Power's Rate Energy Cost Recovery
Rate NDRAlabama Power's Rate Natural Disaster Reserve
Rate RSEAlabama Power's Rate Stabilization and Equalization plan
registrantsSouthern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Southern Power Company, and Southern Company Gas
revenue from contracts with customersRevenue from contracts accounted for under the guidance of ASC 606, Revenue from Contracts with Customers
ROEReturn on equity
S&PS&P Global Ratings, a division of S&P Global Inc.
SCSSouthern Company Services, Inc. (the Southern Company system service company)
SECU.S. Securities and Exchange Commission
SNGSouthern Natural Gas Company, L.L.C.
Southern CompanyThe Southern Company
Southern Company GasSouthern Company Gas and its subsidiaries
Southern Company Gas CapitalSouthern Company Gas Capital Corporation, a 100%-owned subsidiary of Southern Company Gas
Southern Company Gas DispositionsSouthern 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 systemSouthern 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 NuclearSouthern Nuclear Operating Company, Inc.
Southern PowerSouthern Power Company and its subsidiaries
SPSHSP SolarSP Solar Holdings I, LP
SP WindSP Wind Holdings II, LLC
Tax Reform LegislationThe Tax Cuts and Jobs Act, which was signed into law on December 22, 2017 and became effective on January 1, 2018
ToshibaToshiba Corporation, the parent company of Westinghouse
Toshiba GuaranteeCertain payment obligations of the EPC Contractor guaranteed by Toshiba
traditional electric operating companiesAlabama Power, Georgia Power, Gulf Power, and Mississippi Power through December 31, 2018; Alabama Power, Georgia Power, and Mississippi Power as of January 1, 2019
TritonTriton Container Investments, LLC
VCMVogtle Construction Monitoring
VIEVariable interest entity
Virginia CommissionVirginia State Corporation Commission

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DEFINITIONS
(continued)

TermMeaning
Virginia Natural GasVirginia Natural Gas, Inc., a wholly-owned subsidiary of Southern Company Gas
Vogtle 3 and 4 AgreementAgreement 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 OwnersGeorgia Power, Oglethorpe Power Corporation, the Municipal Electric Authority of Georgia,MEAG, and the City of Dalton Georgia, an incorporated municipality in the State of Georgia acting by and through its Board of Water, Light, and Sinking Fund Commissioners
Vogtle Services AgreementThe 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
WACOGWeighted average cost of gas
WestinghouseWestinghouse Electric Company LLC

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
8

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

the impact of recent and future federal and state regulatory changes, including environmental laws and regulations governing air, water, land, and protection of other natural resources, and also changes in tax and other laws and regulations to which Southern Company and its subsidiaries are subject, as well as changes in application of existing laws and regulations;
the uncertainty surrounding the Tax Reform Legislation, including implementing regulations and IRS interpretations, actions that may be taken in response by regulatory authorities, and its impact, if any, on the credit ratings of Southern Company and its subsidiaries;
current and future litigation or regulatory investigations, proceedings, or inquiries;
the effects, extent, and timing of the entry of additional competition in the markets in which Southern Company's subsidiaries operate, including from the development and deployment of alternative energy sources such as self-generation and distributed generation technologies;
variations in demand for electricity and natural gas, including those relating to weather, the general economy, population and business growth (and declines), the effects of energy conservation and efficiency measures, and any potential economic impacts resulting from federal fiscal decisions;
available sources and costs of natural gas and other fuels;
limits on pipeline capacity;
transmission constraints;
effects of inflation;
the ability to control costs and avoid cost and schedule overruns during the development, construction, and operation of facilities, including Plant Vogtle Units 3 and 4 which includes components based on new technology that is just beginning initial operation in the global nuclear industry at scale, including changes in labor costs, availability, and productivity, challenges with management of contractors, subcontractors, or vendors, adverse weather conditions, shortages, increased costs or inconsistent quality of equipment, materials, and labor, including any changes related to imposition of import tariffs, contractor or supplier delay, non-performance under construction, operating, or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities (including major equipment failure and system integration), and/or operational performance;
the ability to construct facilities in accordance with the requirements of permits and licenses (including satisfaction of NRC requirements), to satisfy any environmental performance standards and the requirements of tax credits and other incentives, and to integrate facilities into the Southern Company system upon completion of construction;
investment performance of the Southern Company system's employee and retiree benefit plans and nuclear decommissioning trust funds;
advances in technology;
ongoing renewable energy partnerships and development agreements;
state and federal rate regulations and the impact of pending and future rate cases and negotiations, including rate actions relating to fuel and other cost recovery mechanisms;
the ability to successfully operate the electric utilities' generating, transmission, and distribution facilities and Southern Company Gas' natural gas distribution and storage facilities and the successful performance of necessary corporate functions;

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, increased costs, or inconsistent quality of equipment, materials, and labor; contractor or supplier delay; non-performance under construction, operating, or other agreements; operational readiness, including specialized operator training and required site safety programs; engineering or design problems; design and other licensing-based compliance matters, including the timely resolution of ITAAC and the related approvals by the NRC; challenges with start-up activities, including major equipment failure and system integration; and/or operational performance;
the ability to construct facilities in accordance with the requirements of permits and licenses (including satisfaction of NRC requirements), to satisfy any environmental performance standards and the requirements of tax credits and other incentives, and to integrate facilities into the Southern Company system upon completion of construction;
investment performance of the 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 Georgia PSC approvals and FERC and NRC actions;
under certain specified circumstances, a decision by holders of more than 10% of the ownersownership interests of Plant Vogtle Units 3 and 4 not to proceed with construction;construction and the ability of other Vogtle Owners to tender a portion of their ownership interests to Georgia Power following certain construction cost increases;
litigation or other disputes relatedin the event Georgia Power becomes obligated to provide funding to MEAG with respect to the Kemper County energy facility;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, including environmental, health, regulatory, natural disaster, terrorism, and financial risks;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 dispositions of Gulf Power and Southern Power's plants located in FloridaPlant Mankato and the potential sale of a noncontrolling interest in Southern Power's wind facilities,Nacogdoches biomass-fueled facility, which cannot be assured to be completed or beneficial to Southern Company or its subsidiaries;
the possibility that the anticipated benefits from the Merger cannot be fully realized or may take longer to realize than expected and the possibility that costs related to the integration of Southern Company and Southern Company Gas will be greater than expected;
the ability of counterparties of Southern Company and its subsidiaries to make payments as and when due and to perform as required;
the ability to obtain new short- and long-term contracts with wholesale customers;
the direct or indirect effect on the Southern Company system's business resulting from cyber intrusion or physical attack and the threat of physical attacks;
interest rate fluctuations and financial market conditions and the results of financing efforts;
access to capital markets and other financing sources;
changes in Southern Company's and any of its subsidiaries' credit ratings, including impacts on interest rates, access to capital markets, and collateral requirements;
the impacts of any sovereign financial issues, including impacts on interest rates, access to capital markets, impacts on foreign currency exchange rates, counterparty performance, and the economy in general, as well as potential impacts on the benefits of the DOE loan guarantees;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, such as influenzas, or other similar occurrences;
the direct or indirect effects on the Southern Company system's business resulting from incidents affecting the U.S. electric grid, natural gas pipeline infrastructure, or operation of generating or storage resources;
impairments of goodwill or long-lived assets;
the effect of accounting pronouncements issued periodically by standard-setting bodies; and
other factors discussed elsewhere herein and in other reports (including the Form 10-K) filed by the registrants from time to time with the SEC.
The registrants expressly disclaim any obligation to update any forward-looking statements.

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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,
For the Three Months
Ended March 31,
2018 2017 2018 20172019 2018
(in millions) (in millions)(in millions)
Operating Revenues:          
Retail electric revenues$3,740
 $3,777
 $7,308
 $7,171
$3,084
 $3,568
Wholesale electric revenues611
 618
 1,230
 1,149
499
 623
Other electric revenues175
 167
 339
 342
168
 161
Natural gas revenues (includes alternative revenue programs of
$(4), $-, $(27), and $9, respectively)
706
 684
 2,314
 2,214
Natural gas revenues (includes alternative revenue programs of
$(2) and $(24), respectively)
1,474
 1,607
Other revenues395
 184
 808
 326
187
 413
Total operating revenues5,627
 5,430
 11,999
 11,202
5,412
 6,372
Operating Expenses:          
Fuel1,103
 1,092
 2,204
 2,088
850
 1,101
Purchased power236
 211
 503
 390
170
 267
Cost of natural gas228
 232
 949
 951
686
 720
Cost of other sales279
 114
 568
 203
118
 289
Other operations and maintenance1,559
 1,356
 3,008
 2,740
1,312
 1,451
Depreciation and amortization783
 754
 1,552
 1,469
751
 769
Taxes other than income taxes316
 308
 671
 638
329
 355
Estimated loss on plants under construction1,060
 3,012
 1,105
 3,120
2
 44
Gain on dispositions, net(2,497) 
Total operating expenses5,564
 7,079
 10,560
 11,599
1,721
 4,996
Operating Income (Loss)63
 (1,649) 1,439
 (397)
Operating Income3,691
 1,376
Other Income and (Expense):          
Allowance for equity funds used during construction32
 58
 63
 115
32
 30
Earnings from equity method investments31
 28
 72
 67
48
 41
Interest expense, net of amounts capitalized(470) (424) (928) (840)(430) (458)
Other income (expense), net78
 52
 138
 98
78
 60
Total other income and (expense)(329) (286) (655) (560)(272) (327)
Earnings (Loss) Before Income Taxes(266) (1,935) 784
 (957)
Income taxes (benefit)(139) (587) (25) (273)
Consolidated Net Income (Loss)(127) (1,348) 809
 (684)
Dividends on preferred and preference stock of subsidiaries4
 11
 8
 22
Net income attributable to noncontrolling interests23
 22
 17
 17
Consolidated Net Income (Loss) Attributable to
Southern Company
$(154) $(1,381) $784
 $(723)
Earnings Before Income Taxes3,419
 1,049
Income taxes1,360
 113
Consolidated Net Income2,059
 936
Dividends on preferred stock of subsidiaries4
 4
Net loss attributable to noncontrolling interests(29) (6)
Consolidated Net Income Attributable to
Southern Company
$2,084
 $938
Common Stock Data:          
Earnings (loss) per share —       
Earnings per share -   
Basic$(0.15) $(1.38) $0.77
 $(0.73)$2.01
 $0.93
Diluted$(0.15) $(1.37) $0.77
 $(0.72)$1.99
 $0.92
Average number of shares of common stock outstanding (in millions)          
Basic1,014
 998
 1,012
 996
1,038
 1,011
Diluted1,014
 1,005
 1,017
 1,003
1,045
 1,016
Cash dividends paid per share of common stock$0.60
 $0.58
 $1.18
 $1.14
The accompanying notes as they relate to Southern Company are an integral part of these condensed consolidated financial statements.

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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
 For the Three Months
Ended March 31,
 2019 2018
 (in millions)
Consolidated Net Income$2,059
 $936
Other comprehensive income (loss):   
Qualifying hedges:   
Changes in fair value, net of tax of $(9) and $16, respectively(28) 47
Reclassification adjustment for amounts included in net income,
net of tax of $9 and $(6), respectively
28
 (19)
Pension and other postretirement benefit plans:   
Reclassification adjustment for amounts included in net income,
net of tax of $- and $-, respectively

 2
Total other comprehensive income (loss)
 30
Comprehensive Income2,059
 966
Dividends on preferred stock of subsidiaries4
 4
Comprehensive loss attributable to noncontrolling interests(29) (6)
Consolidated Comprehensive Income Attributable to
Southern Company
$2,084
 $968
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 INCOMECASH FLOWS (UNAUDITED)
 For the Three Months
Ended March 31,
 2019 2018
 (in millions)
Operating Activities:   
Consolidated net income$2,059
 $936
Adjustments to reconcile consolidated net income to net cash provided from operating activities —   
Depreciation and amortization, total851
 873
Deferred income taxes191
 34
Allowance for equity funds used during construction(32) (30)
Mark-to-market adjustments46
 (60)
Pension, postretirement, and other employee benefits(53) (27)
Settlement of asset retirement obligations(62) (41)
Stock based compensation expense64
 69
Estimated loss on plants under construction6
 37
Gain on dispositions, net(2,503) 1
Other, net19
 73
Changes in certain current assets and liabilities —   
-Receivables378
 197
-Prepayments(129) (82)
-Natural gas for sale363
 413
-Other current assets17
 7
-Accounts payable(783) (425)
-Accrued taxes928
 (79)
-Accrued compensation(489) (471)
-Other current liabilities(127) 84
Net cash provided from operating activities744
 1,509
Investing Activities:   
Business acquisitions, net of cash acquired(2) (46)
Property additions(1,678) (1,781)
Nuclear decommissioning trust fund purchases(197) (306)
Nuclear decommissioning trust fund sales192
 301
Proceeds from dispositions4,427
 135
Cost of removal, net of salvage(89) (79)
Change in construction payables, net(146) (112)
Investment in unconsolidated subsidiaries(10) (30)
Payments pursuant to LTSAs(28) (73)
Other investing activities(15) (4)
Net cash provided from (used for) investing activities2,454
 (1,995)
Financing Activities:   
Increase in notes payable, net86
 782
Proceeds —   
Long-term debt1,220
 600
Common stock224
 113
Short-term borrowings
 1,200
Redemptions and repurchases —   
Long-term debt(2,429) (1,283)
Short-term borrowings(1,750) (150)
Distributions to noncontrolling interests(36) (13)
Capital contributions from noncontrolling interests3
 8
Payment of common stock dividends(623) (586)
Other financing activities(48) (42)
Net cash provided from (used for) financing activities(3,353) 629
Net Change in Cash, Cash Equivalents, and Restricted Cash(155) 143
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period1,519
 2,147
Cash, Cash Equivalents, and Restricted Cash at End of Period$1,364
 $2,290
Supplemental Cash Flow Information:   
Cash paid (received) during the period for —   
Interest (net of $18 and $17 capitalized for 2019 and 2018, respectively)$462
 $499
Income taxes, net
 (1)
Noncash transactions — Accrued property additions at end of period899
 894
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)
 
 For the Three Months
Ended June 30,
 For the Six Months
Ended June 30,
 2018 2017 2018 2017
 (in millions) (in millions)
Consolidated Net Income (Loss)$(127) $(1,348) $809
 $(684)
Other comprehensive income (loss):       
Qualifying hedges:       
Changes in fair value, net of tax of
$(18), $23, $(3), and $17, respectively
(54) 38
 (8) 29
Reclassification adjustment for amounts included in net income,
net of tax of $21, $(25), $15, and $(26), respectively
64
 (41) 45
 (42)
Pension and other postretirement benefit plans:       
Reclassification adjustment for amounts included in net income,
net of tax of $1, $1, $1, and $1, respectively
2
 1
 4
 2
Total other comprehensive income (loss)12
 (2) 41
 (11)
Comprehensive Income (Loss)(115) (1,350) 850
 (695)
Dividends on preferred and preference stock of subsidiaries4
 11
 8
 22
Comprehensive income attributable to noncontrolling interests23
 22
 17
 17
Consolidated Comprehensive Income (Loss) Attributable to
Southern Company
$(142) $(1,383) $825
 $(734)
Assets At March 31, 2019 At December 31, 2018
  (in millions)
Current Assets:    
Cash and cash equivalents $1,361
 $1,396
Receivables —    
Customer accounts receivable 1,715
 1,726
Energy marketing receivables 529
 801
Unbilled revenues 555
 654
Under recovered fuel clause revenues 73
 115
Other accounts and notes receivable 863
 813
Accumulated provision for uncollectible accounts (46) (50)
Materials and supplies 1,477
 1,465
Fossil fuel for generation 427
 405
Natural gas for sale 189
 524
Prepaid expenses 786
 432
Assets from risk management activities, net of collateral 111
 222
Other regulatory assets 482
 525
Assets held for sale 55
 393
Other current assets 132
 162
Total current assets 8,709
 9,583
Property, Plant, and Equipment:    
In service 102,673
 103,706
Less: Accumulated depreciation 30,834
 31,038
Plant in service, net of depreciation 71,839
 72,668
Other utility plant, net 1,315
 
Nuclear fuel, at amortized cost 885
 875
Construction work in progress 7,598
 7,254
Total property, plant, and equipment 81,637
 80,797
Other Property and Investments:    
Goodwill 5,284
 5,315
Equity investments in unconsolidated subsidiaries 1,598
 1,580
Other intangible assets, net of amortization of $251 and $235
at March 31, 2019 and December 31, 2018, respectively
 585
 613
Nuclear decommissioning trusts, at fair value 1,875
 1,721
Leveraged leases 806
 798
Miscellaneous property and investments 363
 269
Total other property and investments 10,511
 10,296
Deferred Charges and Other Assets:    
Operating lease right-of-use assets, net of amortization 1,881
 
Deferred charges related to income taxes 794
 794
Unamortized loss on reacquired debt 318
 323
Other regulatory assets, deferred 8,191
 8,308
Assets held for sale, deferred 763
 5,350
Other deferred charges and assets 1,292
 1,463
Total deferred charges and other assets 13,239
 16,238
Total Assets $114,096
 $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 STATEMENTS OF CASH FLOWSBALANCE SHEETS (UNAUDITED)
 For the Six Months
Ended June 30,
 2018 2017
 (in millions)
Operating Activities:   
Consolidated net income (loss)$809
 $(684)
Adjustments to reconcile consolidated net income (loss) to net cash provided from operating activities —    
Depreciation and amortization, total1,750
 1,683
Deferred income taxes(338) (270)
Allowance for equity funds used during construction(63) (115)
Pension, postretirement, and other employee benefits(74) (83)
Settlement of asset retirement obligations(97) (87)
Stock based compensation expense83
 73
Estimated loss on plants under construction1,088
 3,120
Impairment charges161
 
Other, net5
 (118)
Changes in certain current assets and liabilities —   
-Receivables94
 107
-Prepayments(73) (61)
-Natural gas for sale, net of temporary LIFO liquidation295
 223
-Other current assets(40) (30)
-Accounts payable(406) (353)
-Accrued taxes213
 (132)
-Accrued compensation(284) (331)
-Retail fuel cost over recovery10
 (187)
-Other current liabilities125
 (14)
Net cash provided from operating activities3,258
 2,741
Investing Activities:   
Business acquisitions, net of cash acquired(64) (1,046)
Property additions(3,828) (3,398)
Nuclear decommissioning trust fund purchases(571) (388)
Nuclear decommissioning trust fund sales566
 383
Dispositions500
 65
Cost of removal, net of salvage(128) (128)
Change in construction payables, net49
 (117)
Investment in unconsolidated subsidiaries(63) (116)
Payments pursuant to LTSAs(103) (132)
Other investing activities18
 (6)
Net cash used for investing activities(3,624) (4,883)
Financing Activities:   
Increase in notes payable, net1,442
 30
Proceeds —   
Long-term debt1,100
 2,958
Common stock222
 417
Short-term borrowings1,650
 1,004
Redemptions and repurchases —   
Long-term debt(3,379) (1,478)
Preferred and preference stock
 (150)
Short-term borrowings(550) 
Distributions to noncontrolling interests(42) (40)
Capital contributions from noncontrolling interests1,210
 73
Payment of common stock dividends(1,194) (1,134)
Other financing activities(223) (75)
Net cash provided from financing activities236
 1,605
Net Change in Cash, Cash Equivalents, and Restricted Cash(130) (537)
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period2,147
 1,992
Cash, Cash Equivalents, and Restricted Cash at End of Period$2,017
 $1,455
Supplemental Cash Flow Information:   
Cash paid during the period for —   
Interest (net of $35 and $55 capitalized for 2018 and 2017, respectively)$927
 $833
Income taxes, net4
 1
Noncash transactions — Accrued property additions at end of period1,067
 629
Liabilities and Stockholders' Equity At March 31, 2019 At December 31, 2018
  (in millions)
Current Liabilities:    
Securities due within one year $2,315
 $3,198
Notes payable 1,251
 2,915
Energy marketing trade payables 532
 856
Accounts payable 2,037
 2,580
Customer deposits 483
 522
Accrued taxes —    
Accrued income taxes 340
 21
Other accrued taxes 331
 635
Accrued interest 412
 472
Accrued compensation 473
 1,030
Asset retirement obligations 417
 404
Other regulatory liabilities 310
 376
Liabilities held for sale 38
 425
Operating lease obligations 226
 
Other current liabilities 754
 852
Total current liabilities 9,919
 14,286
Long-term Debt 40,457
 40,736
Deferred Credits and Other Liabilities:    
Accumulated deferred income taxes 7,937
 6,558
Deferred credits related to income taxes 6,417
 6,460
Accumulated deferred ITCs 2,353
 2,372
Employee benefit obligations 2,084
 2,147
Operating lease obligations, deferred 1,720
 
Asset retirement obligations, deferred 9,011
 8,990
Accrued environmental remediation 261
 268
Other cost of removal obligations 2,304
 2,297
Other regulatory liabilities, deferred 211
 169
Liabilities held for sale, deferred 39
 2,836
Other deferred credits and liabilities 405
 465
Total deferred credits and other liabilities 32,742
 32,562
Total Liabilities 83,118
 87,584
Redeemable Preferred Stock of Subsidiaries 291
 291
Total Stockholders' Equity (See accompanying statements)
 30,687
 29,039
Total Liabilities and Stockholders' Equity $114,096
 $116,914
The accompanying notes as they relate to Southern Company are an integral part of these condensed consolidated financial statements.

THE
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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETSSTATEMENTS OF STOCKHOLDERS' EQUITY (UNAUDITED)
Assets At June 30, 2018 At December 31, 2017
  (in millions)
Current Assets:    
Cash and cash equivalents $1,980
 $2,130
Receivables —    
Customer accounts receivable 1,728
 1,806
Energy marketing receivables 451
 607
Unbilled revenues 769
 810
Under recovered fuel clause revenues 159
 171
Other accounts and notes receivable 621
 698
Accumulated provision for uncollectible accounts (42) (44)
Materials and supplies 1,397
 1,438
Fossil fuel for generation 462
 594
Natural gas for sale 292
 595
Prepaid expenses 398
 452
Other regulatory assets, current 528
 604
Assets held for sale, current 2,704
 12
Other current assets 172
 199
Total current assets 11,619
 10,072
Property, Plant, and Equipment:    
In service 99,626
 103,542
Less: Accumulated depreciation 30,255
 31,457
Plant in service, net of depreciation 69,371
 72,085
Nuclear fuel, at amortized cost 874
 883
Construction work in progress 6,947
 6,904
Total property, plant, and equipment 77,192
 79,872
Other Property and Investments:    
Goodwill 5,315
 6,268
Equity investments in unconsolidated subsidiaries 1,546
 1,513
Other intangible assets, net of amortization of $205 and $186
at June 30, 2018 and December 31, 2017, respectively
 702
 873
Nuclear decommissioning trusts, at fair value 1,829
 1,832
Leveraged leases 788
 775
Miscellaneous property and investments 247
 249
Total other property and investments 10,427
 11,510
Deferred Charges and Other Assets:    
Deferred charges related to income taxes 789
 825
Unamortized loss on reacquired debt 333
 206
Other regulatory assets, deferred 6,302
 6,943
Assets held for sale 4,618
 
Other deferred charges and assets 1,497
 1,577
Total deferred charges and other assets 13,539
 9,551
Total Assets $112,777
 $111,005
 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 thousands) (in millions)
Balance at December 31, 20171,008,532
 (929) $5,037
 $10,470
 $(36) $8,885
 $(189) $1,361
 $25,528
Consolidated net income attributable to
Southern Company

 
 
 
 
 938
 
 
 938
Other comprehensive income
 
 
 
 
 
 30
 
 30
Stock issued4,055
 
 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
 (33) 1
 
 (2) 20
 (41) (2) (24)
Balance at March 31, 20181,012,587
 (962) $5,054
 $10,603
 $(38) $9,257
 $(200) $1,349
 $26,025
                  
Balance at December 31, 20181,034,741
 (953) $5,164
 $11,094
 $(38) $8,706
 $(203) $4,316
 $29,039
Consolidated net income attributable to
Southern Company

 
 
 
 
 2,084
 
 
 2,084
Stock issued6,547
 
 28
 196
 
 
 
 
 224
Stock-based compensation
 
 
 24
 
 
 
 
 24
Cash dividends of $0.60 per share
 
 
 
 
 (622) 
 
 (622)
Contributions from noncontrolling interests
 
 
 
 
 
 
 3
 3
Distributions to noncontrolling interests
 
 
 
 
 
 
 (41) (41)
Net income (loss) attributable to
noncontrolling interests

 
 
 
 
 
 
 (29) (29)
Other
 (39) 
 7
 (2) (1) 
 1
 5
Balance at March 31, 20191,041,288
 (992) $5,192
 $11,321
 $(40) $10,167
 $(203) $4,250
 $30,687
The accompanying notes as they relate to Southern Company are an integral part of these condensed consolidated financial statements.


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

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

SECONDFIRST QUARTER 20182019 vs. SECONDFIRST QUARTER 2017
AND
YEAR-TO-DATE 2018 vs. YEAR-TO-DATE 2017


OVERVIEW
Southern Company is a holding company that owns all of the common stock of the traditional electric operating companies and the parent entities of Southern Power and Southern Company Gas and owns other direct and indirect subsidiaries. Discussion of the results of operations is focused on the Southern Company system's primary businesses of electricity sales by the traditional electric operating companies and Southern Power and the distribution of natural gas by Southern Company Gas. The four traditional electric operating companies are vertically integrated utilities providing electric service in fourthree Southeastern states. Southern Power develops, constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. During the second quarter 2018, Southern Power completed the sale of a 33% equity interest in a newly-formed limited partnership indirectly owning substantially all of its solar facilities. Southern Company Gas distributes natural gas through its natural gas distribution utilities in four states and is involved in several other complementary businesses including gas marketing services,pipeline investments, wholesale gas services, and gas midstream operations. Through June 30, 2018,marketing services. The Southern Company Gas had seven natural gas distribution utilities in seven states. Subsequent to June 30, 2018, Southern Company Gas completed sales of three of its natural gas distribution utilities. During the second quarter 2018, Southern Company Gas completed the sale of Pivotal Home Solutions. Southern Company'ssystem's other business activities include providing energy technologies and services to electric utilities and large industrial, commercial, institutional, and municipal customers. Customer solutions, includesuch as distributed generation systems, utilityenergy infrastructure, solutions, and energy efficiency products and services.services, and utility infrastructure 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. See FUTURE EARNINGS POTENTIAL and Note (J) to the Condensed Financial Statements herein for additional information regarding disposition activity.
On May 20, 2018,January 1, 2019, Southern Company entered into a stock purchase agreement withcompleted its sale of Gulf Power to NextEra Energy to sell Gulf Power for an aggregate cash purchase price of $5.75approximately $5.8 billion (less the amount$1.3 billion of indebtedness assumed at closing, which is currently estimated at approximately $1.4 billion)assumed), subject to certaincustomary working capital adjustments. The completion ofpreliminary gain associated with the sale is subject to the satisfaction or waiver of certain closing conditions and is expected to occur in the first half of 2019. The ultimate outcome of this matter cannot be determined at this time.Gulf Power totaled $2.5 billion pre-tax ($1.3 billion after tax). See Note (J)(K) to the Condensed Financial Statements under "Southern Company's Sale of Gulf PowerCompany" herein for additional information.
Alabama Power, Georgia Power Gulf Power, Mississippi Power,and Atlanta Gas Light are required to file base rate cases with the Georgia PSC by July 1, 2019 and June 3, 2019, respectively. Nicor Gas recently reached agreementsfiled a rate case with their respective state PSCs or other applicable state regulatory agencies relating to the regulatory impacts of the Tax Reform Legislation, which, for some companies, included capital structure adjustmentsIllinois Commission in November 2018. These three rate cases are expected to help mitigateconclude in 2019. In addition, Mississippi Power is scheduled to file a base rate case with the potential adverse impacts to certainMississippi PSC in the fourth quarter 2019. The ultimate outcome of their credit metrics.these matters cannot be determined at this time. See Note (B) to the Condensed Financial Statements under "Regulatory Matters" herein for additional information regarding state PSC or other regulatory agency actions related to the Tax Reform Legislation. Also see MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax"Regulatory Matters" of Southern Companyherein and Note 2 to the financial statements in Item 78 of the Form 10-K and FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" and Note (H) to the Condensed Financial Statements herein for information regarding the Tax Reform Legislation.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.

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Plant Vogtle Units 3 and 4 Status
In 2009, the Georgia PSC certified construction of Plant Vogtle Units 3 and 4 (with electric generating capacity of approximately 1,100 MWs each). 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 recognized as a regulatory liability in 2017). AlthoughRefunds), with respect to Georgia Power believes these incremental costs are reasonable and necessary to complete the project and the Georgia PSC has stated the $7.3 billion estimate included in the seventeenth VCM proceeding does not represent a cost cap, Georgia Power does not intend to seek rate recovery for the $0.7 billion increase in costs included in the revised base capital cost forecast, which will be filed with the Georgia PSC in the nineteenth VCM report on August 31, 2018. In connection with future VCM filings, Georgia Power may request the Georgia PSC to evaluate costs included in the revised construction contingency estimate for rate recovery as and when they are appropriately included in the base capital cost forecast. After considering the significant level of uncertainty that exists regarding the future recoverability of costs included in the construction contingency estimate since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in these future regulatory proceedings, Georgia Power has recorded a total pre-tax charge to income of $1.1 billion ($0.8 billion after tax) as of June 30, 2018.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

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Vogtle Units 3 and 4 mustwere required to vote to continue construction. TheIn September 2018, the Vogtle Owners are expectedunanimously voted to conduct these votes incontinue construction of Plant Vogtle Units 3 and 4. In connection with the third quarter 2018.
Ifvote to continue construction, Georgia Power entered into (i) a binding term sheet (Vogtle Owner Term Sheet) with the holdersother Vogtle Owners and certain of at least 90% ofMEAG'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 interestsinterest in Plant Vogtle Units 3 and 4 do not voteunder certain circumstances. On January 14, 2019, Georgia Power, MEAG, and MEAG SPVJ entered into an agreement to continue construction,implement the Vogtle Joint Ownership Agreements provide that the project will be cancelled, and construction will cease. In the event that fewer than 90%provisions of the Vogtle Owners vote to continue construction,MEAG Term Sheet. On February 18, 2019, Georgia Power, and the other Vogtle Owners, will assess optionsand 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. If Plant Vogtle Units 3 and 4 were cancelled and Georgia Power was unable to recover costs it has incurred in connection with the project, Southern Company's results of operations, cash flow, and financial condition would be materially impacted. The ultimate outcome of this matter cannot be determined at this time.
Georgia Power's revised cost estimate reflects an expected in-service datedates of November 2021 for Unit 3 and November 2022 for Unit 4.4, 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 March 31, 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 ProgramNuclear Construction" and ACCOUNTING POLICIES –Note (F) to the Condensed Financial Statements under "Application of Critical Accounting Policies and EstimatesDOE Loan Guarantee Borrowings" herein for additional information.
RESULTS OF OPERATIONS
Net Income (Loss)
Second Quarter 2018 vs. Second Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$1,227 N/M $1,507 N/M
First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change)
$1,146 122.2
N/M - Not meaningful
Consolidated net lossincome attributable to Southern Company was $(154) million$2.1 billion ($(0.15)2.01 per share) for the secondfirst quarter 20182019 compared to a net loss of $(1.4) billion$938 million ($(1.38)0.93 per share) for the corresponding period in 2017.2018. The changeincrease was primarily due to charges of $3.01the $2.5 billion ($2.121.3 billion after tax) gain on the sale of Gulf Power in 2017 related2019, partially offset by a decrease in retail revenues due to milder weather compared to the Kemper IGCC atcorresponding period in 2018. See Note (K) to the Condensed Financial Statements under "Southern Company" herein for additional information.
Retail Electric Revenues
First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change)
$(484) (13.6)
In the first quarter 2019, retail electric revenues were $3.1 billion compared to $3.6 billion for the corresponding period in 2018.

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Mississippi Power, partially offset by a $1.1 billion ($0.8 billion after tax) charge in the second quarter 2018 for an estimated probable loss on Georgia Power's construction of Plant Vogtle Units 3 and 4. Also contributing to the change were lower federal income tax expense as a result of the Tax Reform Legislation and higher retail electric revenues due to warmer weather in the second quarter 2018 compared to the corresponding period in 2017, partially offset by increased operations and maintenance expenses and reductions in retail revenues related to the regulatory treatment of the Tax Reform Legislation impacts.
Consolidated net income attributable to Southern Company was $784 million ($0.77 per share) for year-to-date 2018 compared to a net loss of $(723) million ($(0.73) per share) for the corresponding period in 2017. The change was primarily due to charges of $3.12 billion ($2.18 billion after tax) in 2017 related to the Kemper IGCC at Mississippi Power, partially offset by a $1.1 billion ($0.8 billion after tax) charge in the second quarter 2018 for an estimated probable loss on Georgia Power's construction of Plant Vogtle Units 3 and 4. Also contributing to the change were lower federal income tax expense as a result of the Tax Reform Legislation and higher retail electric revenues due to colder weather in the first quarter 2018 and warmer weather in the second quarter 2018 compared to the corresponding periods in 2017, partially offset by increased operations and maintenance expenses and reductions in retail revenues related to the regulatory treatment of the Tax Reform Legislation impacts.
Retail Electric Revenues
Second Quarter 2018 vs. Second Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(37) (1.0) $137 1.9
In the second quarter 2018, retail electric revenues were $3.7 billion compared to $3.8 billion for the corresponding period in 2017. For year-to-date 2018, retail electric revenues were $7.3 billion compared to $7.2 billion for the corresponding period in 2017.
Details of the changes in retail electric revenues were as follows:
 Second Quarter 2018 Year-to-Date 2018 First Quarter 2019
 (in millions) (% change) (in millions) (% change) (in millions) (% change)
Retail electric – prior year $3,777
   $7,171
   $3,568
  
Estimated change resulting from –            
Rates and pricing (141) (3.7) (245) (3.4) 58
 1.6
Sales growth (decline) (5) (0.1) 22
 0.3
Sales decline (11) (0.3)
Weather 73
 1.9
 217
 3.0
 (91) (2.6)
Fuel and other cost recovery 36
 0.9
 143
 2.0
 (150) (4.2)
Gulf Power disposition (290) (8.1)
Retail electric – current year $3,740
 (1.0)% $7,308
 1.9 % $3,084
 (13.6)%
Revenues associated with changes in rates and pricing decreasedincreased in the secondfirst quarter and year-to-date 20182019 when compared to the corresponding periodsperiod in 20172018 primarily due to revenues deferred as regulatory liabilities for future adjustments to customer billingsincreases under Rate CNP Compliance at Alabama Power and increases related to PEP and ECO Plan rate changes that became effective for the Tax Reform Legislation and a decrease in the recoveryfirst billing cycle of Plant Vogtle Units 3 and 4 construction financing costs under the NCCR tariffSeptember 2018 at Georgia Power, also primarily related to the Tax Reform Legislation. Also contributing to the year-to-date 2018 decrease was the rate pricing effect of increased customer usage at Georgia Power. These decreases were partially offset by higher contributions from variable demand-driven pricing from commercial and industrial customers at GeorgiaMississippi Power.
See Note 32 to the financial statements of Southern Company under "Regulatory Matters – Alabama Power," " Georgia Power Rate Plans,""Alabama Power" and " Gulf Power Retail Base Rate Cases""Mississippi Power" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for additional information.

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Revenues attributable to changes in sales decreased in the secondfirst quarter 20182019 when compared to the corresponding period in 2017. Weather-adjusted2018. In the first quarter 2019, weather-adjusted residential KWH sales were flat in the second quarter 2018, primarily due to customer growth, offset by decreased customer usage. Weather-adjusted commercial KWH sales decreased 0.2% in the second quarter 2018, primarily due to decreased customer usage, partially offset by customer growth. Industrial KWH sales increased 0.6% in the second quarter 2018, primarily in the primary metals and stone, clay, and glass sectors, partially offset by decreased sales in the paper sector.
Revenues attributable to changes in sales increased for year-to-date 2018 when compared to the corresponding period in 2017. Weather-adjusted residential KWH sales and weather-adjusted commercial KWH sales increased 0.6% and 0.5%, respectively, for year-to-date 2018,0.4% primarily due to customer growth, partially offset by decreased customer usage.usage primarily resulting from an increase in energy efficient residential appliances. Weather-adjusted commercial KWH sales decreased 1.9% primarily due to decreased customer usage resulting from an increase in energy saving initiatives, partially offset by customer growth. Industrial KWH sales increased 1.6% for year-to-datedecreased 2.0% in the first quarter 2019 when compared to the corresponding period in 2018 as a result of a decrease in demand resulting from changes in production levels primarily in the primary metals, chemicals, and stone, clay and glasspaper sectors, partially offset by decreased salesincreased demand in the paperpipeline sector.
Fuel and other cost recovery revenues increased $36 million and $143decreased $150 million in the secondfirst quarter and year-to-date 2018, respectively, when2019 compared to the corresponding periodsperiod in 20172018 primarily due to higherdecreased energy sales driven by milder weather, resulting from colder weather in the first quarter 2018lower customer demand and warmer weather in the second quarter 2018 compared to the corresponding periods in 2017.lower generation costs. 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 2018 vs. Second Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(7) (1.1) $81 7.0
First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change)
$(124) (19.9)
Wholesale electric revenues consist of PPAs primarily with investor-owned utilities and electric cooperatives and short-term opportunity sales. Wholesale electric revenues from PPAs (other than solar and wind PPAs) have both capacity and energy components. Capacity revenues generally represent the greatest contribution to net income and are designed to provide recovery of fixed costs plus a return on investment. Energy revenues will vary depending on fuel prices, the market prices of wholesale energy compared to the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not

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have a significant impact on net income. Energy sales from solar and wind PPAs do not have a capacity charge and customers either purchase the energy output of a dedicated renewable facility through an energy charge or through a fixed price related to the energy. As a result, Southern Company'sthe ability to recover fixed and variable operations and maintenance expenses is dependent upon the level of energy generated from these facilities, which can be impacted by weather conditions, equipment performance, transmission constraints, and other factors. Wholesale electric revenues at Mississippi Power include FERC-regulated municipal and rural association sales under cost-based tariffs as well as market-based sales. Short-term opportunity sales are made at market-based rates that generally provide a margin above the Southern Company system's variable cost to produce the energy.
For year-to-date 2018,In the first quarter 2019, wholesale electric revenues were $1.2 billion$499 million compared to $1.1 billion$623 million for the corresponding period in 2017.2018. This increasedecrease was related to a $90$106 million increasedecrease in energy revenues partially offset by a $9and an $18 million decrease in capacity revenues. The year-to-date 2018 increaseExcluding a decrease of $7 million of energy revenues related to the sale of Gulf Power, the decrease in energy revenues primarily related to Southern Power and included an increase in fuel costs that are contractually recovered through PPAs, revenues from new natural gas PPAs from existing facilities, and an increase in sales from renewable facilities, partially offset by a decrease in non-PPA revenues fromdue to a decrease in the volume of KWHs sold through short-term sales.sales, primarily due to a reduction in uncovered natural gas capacity, as well as a decrease in revenues related to natural gas PPAs due to a decrease in the average cost of fuel and purchased power, partially offset by an increase in the volume of KWHs sold due to increased customer load. The decrease was also due to lower fuel prices and lower customer demand due to milder weather at the traditional electric operating companies. The decrease in capacity revenues primarily related to the sales of Gulf Power and Southern Power's Plant Oleander and Plant Stanton Unit A. 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
First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change)
$(133) (8.3)
In the first quarter 2019, natural gas revenues were $1.5 billion compared to $1.6 billion for the corresponding period in 2018.
Details of the changes in natural gas revenues were as follows:
  First Quarter 2019
  (in millions) (% change)
Natural gas revenues – prior year $1,607
  
Estimated change resulting from –    
Infrastructure replacement programs and base rate changes 32
 2.0
Gas costs and other cost recovery 62
 3.9
Weather 7
 0.4
Wholesale gas services (80) (5.0)
Southern Company Gas Dispositions (167) (10.4)
Other 13
 0.8
Natural gas revenues – current year $1,474
 (8.3)%
Revenues attributable to infrastructure replacement programs and base rate changes at the natural gas distribution utilities increased for the first quarter 2019 compared to the corresponding period in 2018 primarily due to a $22 million increase at Nicor Gas and a $9 million increase 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.

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Natural Gas Revenues
Second Quarter 2018 vs. Second Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$22 3.2 $100 4.5
In the second quarter 2018, natural gas revenues were $706 million compared to $684 million for the corresponding period in 2017. For year-to-date 2018, natural gas revenues were $2.3 billion compared to $2.2 billion for the corresponding period in 2017.
Details of the changes in natural gas revenues were as follows:
 Second Quarter 2018 Year-to-Date 2018
 (in millions) (% change) (in millions) (% change)
Natural gas revenues – prior year$684
   $2,214
  
Estimated change resulting from –       
Infrastructure replacement programs and base rate changes38
 5.6 % 48
 2.2 %
Gas costs and other cost recovery(4) (0.6)% (2) (0.1)
Weather8
 1.2 % 16
 0.7
Wholesale gas services(4) (0.6)% 31
 1.4
Other(16) (2.4)% 7
 0.3
Natural gas revenues – current year$706
 3.2 % $2,314
 4.5 %
The increases in natural gas revenues in the second quarter and year-to-date 2018 were primarily related to continued infrastructure investments recovered through replacement programs and base rate changes at the natural gas distribution utilities. These changes include base rate increases as a result of rate cases, partially offset by revenue reductions for the impacts of the Tax Reform Legislation.
Revenues attributable to gas costs and other cost recovery decreased due to reduced natural gas prices during 2018increased in the first quarter 2019 compared to the corresponding periodsperiod in 2017, partially offset by2018 primarily due to higher natural gas prices and increased volumes of natural gas sold in 2018 as a result of colder weather, as determined by Heating Degree Days.
Revenues increased due to colder weather, as determined by Heating Degree Days, in 2018 compared to the corresponding periods in 2017 that affected the utility customers in Illinois andat Southern Company Gas' remaining four natural gas marketing services customers in Georgia and Illinois.
Revenues attributable to Southern Company Gas' wholesale gas services business decreaseddistribution utilities in the secondfirst quarter 2018 primarily due to derivative losses, partially offset by increased commercial activity and increased for year-to-date 2018 primarily due to increased commercial activity, partially offset by derivative losses.
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 operations.utilities.
Revenues increased due to colder weather, as determined by Heating Degree Days, in Illinois in the first quarter 2019 compared to the corresponding period in 2018.
Revenues attributable to Southern Company Gas' wholesale gas services business decreased in the first quarter 2019 compared to the corresponding period in 2018 primarily due to decreased commercial activity, partially offset by derivative gains.
See Note (B) to the Condensed Financial Statements herein under "Regulatory MattersSouthern Company Gas" for additional information.

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Other Revenues
Second Quarter 2018 vs. Second Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$211 114.7 $482 147.9
First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change)
$(226) (54.7)
In the secondfirst quarter 2018,2019, other revenues were $395$187 million compared to $184$413 million for the corresponding period in 2017. For year-to-date 2018, other revenues were $808 million compared to $326 million for the corresponding period in 2017. These increases were2018. The decrease was primarily duerelated to PowerSecure's 2018 storm restoration services in Puerto Rico.
Fuel and Purchased Power Expenses
Second Quarter 2018
vs.
Second Quarter 2017
 Year-to-Date 2018
vs.
Year-to-Date 2017
 First Quarter 2019
vs.
First Quarter 2018
(change in millions) (% change) (change in millions) (% change) (change in millions) (% change)
Fuel$11
 1.0 $116
 5.6 $(251) (22.8)
Purchased power25
 11.8 113
 29.0 (97) (36.3)
Total fuel and purchased power expenses$36
 $229
  $(348) 
In the secondfirst quarter 2018,2019, total fuel and purchased power expenses were $1.34$1.0 billion compared to $1.30$1.4 billion for the corresponding period in 2017. The increase2018. Excluding a decrease of $121 million related to the sale of Gulf Power, the decrease was primarily the result of an $87 million increase in the volume of KWHs generated and purchased, partially offset by an $80a $149 million decrease in the average cost of fuel and purchased power.
For year-to-date 2018, total fuelpower and purchased power expenses were $2.7 billion compared to $2.5 billion fora $78 million net decrease in the corresponding period in 2017. The increase was primarily the result of a $234 million increase in theaggregate volume of KWHs generated and purchased, partially offset by a $34 million net decrease in the average cost of fuel and purchased power.
In addition, fuel expense increased $30 million in both the second quarter and year-to-date 2018 in accordance with an Alabama PSC accounting order authorizing the use of excess deferred income taxes to offset under recovered fuel costs.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 MattersFuel Cost Recovery" and Recovery" – Alabama Power – Accounting Order" herein for additional information. Fuel expenses incurred under Southern Power's PPAs are generally the responsibility of the counterparties and do not significantly impact net income.

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Details of the Southern Company system's generation and purchased power were as follows:
Second Quarter 2018 Second Quarter 2017 Year-to-Date 2018 Year-to-Date 2017 First Quarter 2019 
First Quarter 2018(a)
Total generation (in billions of KWHs)
49 49 97 92 43 46
Total purchased power (in billions of KWHs)
5 4 10 9 4 3
Sources of generation (percent)
     
Gas46 44 46 45 48 45
Coal30 30 29 29 22 29
Nuclear14 16 15 16 16 16
Hydro3 3 3 3 8 4
Other7 7 7 7 6 6
Cost of fuel, generated (in cents per net KWH)
     
Gas2.74 2.94 2.80 2.93 2.56 2.84
Coal2.75 2.85 2.82 2.87 2.92 2.88
Nuclear0.82 0.80 0.80 0.80 0.79 0.78
Average cost of fuel, generated (in cents per net KWH)(a)
2.44 2.51 2.47 2.51 2.32 2.47
Average cost of purchased power (in cents per net KWH)(b)
5.00 5.47 5.64 5.28 4.50 7.04
(a)Cost of fuel and average cost of fuel, generated excludes a $30 million adjustment associated with the Alabama PSC accounting order related to excess deferred income taxes.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.
Fuel
In the secondfirst quarter 2018,2019, fuel expense was $1.10 billion$850 million compared to $1.09$1.1 billion for the corresponding period in 2017. The increase2018. Excluding approximately $54 million related to Gulf Power in 2018, the decrease was primarily due to a 6.9% increase in the volume of KWHs generated by natural gas and a 1.7% increase29.1% decrease in the volume of KWHs generated by coal partially offset byand a 6.8%9.9% decrease in the average cost of natural gas per KWH generated and a 3.5% decrease in the average cost of coal per KWH generated.
For year-to-date 2018, fuel expense was $2.2 billion compared to $2.1 billion for the corresponding period in 2017. The increase was primarily due to a 10.4% increase in the volume of KWHs generated by natural gas and a 5.9% increase in the volume of KWHs generated by coal, partially offset by a 4.4% decrease in the average cost of natural gas per KWH generated and a 1.7% decrease in the average cost of coal per KWH generated.
Purchased Power
In the secondfirst quarter 2018,2019, purchased power expense was $236$170 million compared to $211$267 million for the corresponding period in 2017. The increase2018. Excluding approximately $67 million of non-affiliated purchases by Gulf Power in 2018 and $22 million of non-affiliated purchases from Gulf Power in 2019 that would have been eliminated in consolidation in 2018, the decrease was primarily due to an 18.4% increase in the volume of KWHs purchased, partially offset by an 8.6%a 29.1% decrease in the average cost per KWH purchased.
For year-to-date 2018, purchased power expense was $503 million compared See Note (K) to $390 millionthe Condensed Financial Statements under "Southern Company" herein for information regarding the corresponding period in 2017. The increase was primarily due to a 16.3% increase in the volumesale of KWHs purchased and a 6.8% increase in the average cost per KWH purchased.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
First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change)
$(34) (4.7)
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

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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 87% of total cost of natural gas for the first quarter 2019.
In the first quarter 2019, cost of natural gas was $686 million compared to $720 million for the corresponding period in 2018. Excluding a $79 million decrease related to the Southern Company Gas Dispositions, cost of natural gas increased $45 million. This increase reflects a 4.9% increase in natural gas prices and an increase in the volume of natural gas sold in the first quarter 2019 primarily as a result of colder weather in Illinois, as determined by Heating Degree Days, compared to the corresponding period in 2018.
Cost of Other Sales
Second Quarter 2018 vs. Second Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$165 144.7 $365 179.8
First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change)
$(171) (59.2)
In the secondfirst quarter 2018,2019, cost of other sales was $279$118 million compared to $114$289 million for the corresponding period in 2017. For year-to-date 2018, cost of other sales2018. The decrease was $568 million compared to $203 million for the corresponding period in 2017. These increases primarily reflect costs related to PowerSecure's 2018 storm restoration services in Puerto Rico.
Other Operations and Maintenance Expenses
Second Quarter 2018 vs. Second Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$203 15.0 $268 9.8
First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change)
$(139) (9.6)
In the secondfirst quarter 2018,2019, other operations and maintenance expenses were $1.6 billion compared to $1.4 billion for the corresponding period in 2017. The increase was primarily due to an asset impairment charge of $119 million at Southern Power related to the pending sale of its Florida plants, a $36 million loss on the sale of Pivotal Home Solutions at Southern Company Gas, and a $27 million increase in transmission and distribution costs, primarily related to line maintenance.
For year-to-date 2018, other operations and maintenance expenses were $3.0 billion compared to $2.7 billion for the corresponding period in 2017. The increase was primarily due to an asset impairment charge of $119 million at Southern Power related to the pending sale of its Florida plants, a $42 million goodwill impairment charge at Southern Company Gas related to the sale of Pivotal Home Solutions, and a $36 million loss on the sale of Pivotal Home Solutions at Southern Company Gas. Also contributing to the increase were a $38 million increase in transmission and distribution costs, primarily related to line maintenance, a $19 million decrease in gains from sales of integrated transmission system assets at Georgia Power, and a $12 million increase at Southern Company Gas to align paid time off with the Southern Company system's policy. These increases were partially offset by $32.5 million resulting from the write-down of Gulf Power's ownership of Plant Scherer Unit 3 in the first quarter 2017 in accordance with a settlement agreement approved by the Florida PSC in April 2017 (2017 Gulf Power Rate Case Settlement Agreement).
See Note (A) to the Condensed Financial Statements under "Goodwill and Other Intangible Assets" and Note (J) to the Condensed Financial Statements under "Southern Company GasSale of Pivotal Home Solutions" and "Southern Power – Sale of Florida Plants" herein for additional information. Also see Note 3 to the financial statements of Southern Company under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" in Item 8 of the Form 10-K for additional information regarding the 2017 Gulf Power Rate Case Settlement Agreement.
Depreciation and Amortization
Second Quarter 2018 vs. Second Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$29 3.8 $83 5.7
In the second quarter 2018, depreciation and amortization was $783 million compared to $754 million for the corresponding period in 2017. For year-to-date 2018, depreciation and amortization was $1.6$1.3 billion compared to $1.5 billion for the corresponding period in 2017. These increases primarily reflect increases2018. The decrease reflects approximately $76 million related to Gulf Power in 2018 and $71 million related to the Southern Company Gas Dispositions, including the $42 million goodwill impairment charge recorded in contemplation of $31the sale of Pivotal Home Solutions.
Depreciation and Amortization
First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change)
$(18) (2.3)
In the first quarter 2019, depreciation and amortization was $751 million and $65compared to $769 million for the second quartercorresponding period in 2018. The decrease was primarily due to decreases of $47 million related to the sale of Gulf Power and year-to-date 2018, respectively,$16 million related to the Southern Company Gas Dispositions, partially offset by an increase of $33 million related to additional plant in service.

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Additionally, these increases were due to depreciation credits of $8.5 million and $34 million recognized in the second quarter and year-to-date 2017, respectively, as authorized in Gulf Power's 2013 rate case settlement.
See Note 3 to the financial statements of Southern Company under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" in Item 8 of the Form 10-K for additional information.
Taxes Other Than Income Taxes
Second Quarter 2018 vs. Second Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$8 2.6 $33 5.2
First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change)
$(26) (7.3)
In the secondfirst quarter 2018,2019, taxes other than income taxes were $316$329 million compared to $308$355 million for the corresponding period in 2017. For year-to-date 2018, taxes other than income taxes were $671 million compared to $638 million for the corresponding period in 2017. These increases were2018. The decrease primarily due to increased property taxes at Georgia Power, increased revenue tax expenses at Southern Company Gas, and increased payroll taxes related to aligning paid time off at Southern Company Gas with the Southern Company system's policy. Also contributingrelates to the year-to-date 2018 increase was an increase in municipal franchise fees primarily related to higher retail revenues at Georgiasale of Gulf Power.
Estimated Loss on Plants Under Construction
Second Quarter 2018 vs. Second Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(1,952) (64.8) $(2,015) (64.6)
In the second quarter 2018, estimated loss on plants under construction was $1.06 billion compared to $3.01 billion for the corresponding period in 2017. For year-to-date 2018, estimated loss on plants under construction was $1.11 billion compared to $3.12 billion for the corresponding period in 2017. These decreases were primarily related to revisions to the estimated construction costs for, and subsequent suspension of, the Kemper IGCC in June 2017 at Mississippi Power, partially offset by Georgia Power's revised estimate to complete construction and start-up of Plant Vogtle Units 3 and 4 in the second quarter 2018.
See Note 3 to the financial statements of Southern Company under "Kemper County Energy Facility" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Kemper County Energy Facility" and "Nuclear Construction" herein for additional information.
Allowance for Equity Funds Used During Construction
Second Quarter 2018 vs. Second Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(26) (44.8) $(52) (45.2)
In the second quarter 2018, AFUDC equity was $32 million compared to $58 million in the corresponding period in 2017. For year-to-date 2018, AFUDC equity was $63 million compared to $115 million in the corresponding period in 2017. These decreases primarily resulted from Mississippi Power's suspension of the Kemper IGCC construction in June 2017, partially offset by increases in capital expenditures related to environmental and transmission projects at Alabama Power.
See Note 3 to the financial statements of Southern Company under "Kemper County Energy Facility" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Kemper County Energy Facility" herein for additional information.

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Estimated Loss on Plants Under Construction
First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change)
$(42) (95.5)
In the first quarter 2019, estimated loss on plants under construction was $2 million compared to $44 million for the corresponding period in 2018. The decrease was primarily due to lower costs associated with 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 "Mississippi PowerKemper County Energy Facility" for additional information.
Gain on Dispositions, Net
First Quarter 2019 vs. First Quarter 2018
(change in millions)(% change)
$2,497N/M
N/M - Not meaningful
In the first quarter 2019, a net gain on dispositions of $2.5 billion ($1.3 billion gain after tax) was recorded related to 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 2018 vs. Second Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$46 10.8 $88 10.5
First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change)
$(28) (6.1)
In the secondfirst quarter 2018,2019, interest expense, net of amounts capitalized was $470$430 million compared to $424$458 million in the corresponding period in 2017. For year-to-date 2018, interest expense, net2018. Excluding a decrease of amounts capitalized$13 million related to the sale of Gulf Power, the decrease was $928 million compared to $840 million in the corresponding period in 2017. These increases were largely due to an increase in average outstanding long-term debt, primarily at the parent company and Southern Company Gas.immaterial.
See FINANCIAL CONDITION AND LIQUIDITY – "Financing Activities" herein, Note 68 to the financial statements of Southern Company in Item 8 of the Form 10-K, and Note (F) to the Condensed Financial Statements herein for additional information.
Other Income (Expense), Net
Second Quarter 2018 vs. Second Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$26 50.0 $40 40.8
First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change)
$18 30.0
In the secondfirst quarter 2018,2019, other income (expense), net was $78 million compared to $52$60 million for the corresponding period in 2017. For year-to-date 2018, other income (expense), net2018. The increase was $138 million compared to $98 million for the corresponding period in 2017. These increases were primarily due to the settlement of Mississippi Power's Deepwater Horizon claiman increase in May 2018. The year-to-date 2018 increase was also due tointerest income from a gain from the settlement ofnew tolling arrangement accounted for as a contractor litigation claim at Southern Company Gas.
See Note (B) to the Condensed Financial Statements under "General Litigation Matters – Mississippi Power" and "Southern Company GasAtlanta Gas Light's Pipeline Replacement Program" herein for additional information.
Income Taxes (Benefit)
Second Quarter 2018 vs. Second Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$448 N/M $248 N/M
N/M - Not meaningful
In the second quarter 2018, income tax benefit was $139 million compared to an income tax benefit of $587 million for the corresponding period in 2017. For year-to-date 2018, income tax benefit was $25 million compared to an income tax benefit of $273 million for the corresponding period in 2017. These changes were primarily due to charges recorded in 2017 related to the Kemper IGCClease at Mississippi Power partially offset by the estimated probable loss on Plant Vogtle Units 3 and 4 at Georgia Power in the second quarter 2018 and lower federal income tax expense as well as the benefit from the flowback of excess deferred income taxes as a result of the Tax Reform Legislation. The year-to-date 2018 change was also due to net state income tax benefits arising from the reorganization of Southern Power's legal entities holding its solar facilities.
See Note (H) to the Condensed Financial Statements herein for additional information.temporary cash investments.

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Dividends on Preferred and Preference Stock of SubsidiariesIncome Taxes
Second Quarter 2018 vs. Second Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(7) (63.6) $(14) (63.6)
First Quarter 2019 vs. First Quarter 2018
(change in millions)(% change)
$1,247N/M
N/M - Not meaningful
In the secondfirst quarter 2018, dividends on preferred and preference stock of subsidiaries was $4 million2019, income taxes were $1.4 billion compared to $11$113 million for the corresponding period in 2017. For year-to-date 2018, dividends on preferred and preference stock of subsidiaries2018. The increase was $8 million compared to $22 million for the corresponding period in 2017. These decreases were primarily due to tax expense related to the 2017 redemptionssale of all outstanding shares of preferred and preference stock at Georgia Power and preference stock at Gulf Power.
See Notes (G) and (K) to the Condensed Financial Statements herein for additional information.
Net Loss Attributable to Noncontrolling Interests
First Quarter 2019 vs. First Quarter 2018
(change in millions)(% change)
$23N/M
N/M - Not meaningful
Substantially all noncontrolling interests relate to renewable projects at Southern Power. See Note 67 to the financial statements of Southern Company under "Redeemable Preferred Stock of Subsidiaries" in Item 8 of the Form 10-K under "Southern Power" for additional information.
In the first quarter 2019, net loss attributable to noncontrolling interests was $29 million compared to $6 million for the corresponding period in 2018. The increase was primarily related to tax equity partnerships entered into in 2018.
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 a constructive regulatory environmentenvironments that allowsallow for the timely recovery of prudently-incurred costs during a time of increasing costs, continued customer growth, and, limited projected demandfor the traditional electric operating companies, the weak pace of growth over the next several years.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 and successful additional investments in renewable and other energy projects are also major factors.
Future earnings for the electricity and natural gas businesses will be driven primarily by customer growth. Earnings in the electricity business will also depend upon maintaining and growing sales, considering, among other things, the adoption and/or penetration rates of increasingly energy-efficient technologies, increasing volumes of electronic commerce transactions, and more multi-family home construction, all of which could contribute to a net reduction in customer usage. Earnings for both the electricity and natural gas businesses are subject to a variety of other factors. These factors include weather, competition, new energy contracts with other utilities and other wholesale customers, energy conservation practiced by customers, the use of alternative energy sources by customers, the prices of electricity and natural gas, the price elasticity of demand, and the rate of economic growth or decline in the service territory. In addition, the level of future earnings for the wholesale electric business also depends on numerous factors including regulatory matters, creditworthiness of customers, total electric generating capacity available and related costs, future acquisitionsthe development or acquisition of renewable facilities and construction of electric generating facilities, the impact of tax credits from renewableother 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

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other energy sources, and the ability of Southern Company Gas' gas marketing services and wholesale gas services businesses to capture value from locational and seasonal spreads. Additionally, changes in commodity prices subject a significant portion of Southern Company Gas' operations to earnings variability.
As part of its ongoing effort to adapt to changing market conditions, Southern Company continues to evaluate and consider a wide array of potential business strategies. These strategies may include business combinations, partnerships, and acquisitions involving other utility or non-utility businesses or properties, disposition of certain assets or businesses, internal restructuring, or some combination thereof. Furthermore, Southern Company may engage in new business ventures that arise from competitive and regulatory changes in the utility industry. Pursuit of any of the above strategies, or any combination thereof, may significantly affect the business operations, risks, and financial condition of Southern Company.

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On May 20, 2018, Southern Company entered into a stock purchase agreement with NextEra Energy to sell of all of the capital stock of Gulf Power for an aggregate cash purchase price of $5.75 billion (less the amount of indebtedness assumed at closing, which is currently estimated at approximately $1.4 billion), subject to (i) customary adjustments for indebtedness and working capital and (ii) reduction by the amount (if any) by which Gulf Power fails to meet a specified capital expenditure target. The completion of the sale is subject to the satisfaction or waiver of certain closing conditions, including, among others, (i) the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act, (ii) approval by the FERC and the Federal Communications Commission, (iii) the entry into certain ancillary agreements, including transmission-related agreements and a transition services agreement, among the parties and their affiliates, and (iv) other customary closing conditions. Southern Company's sale of Gulf Power is expected to occur in the first half of 2019. See Note (J) to the Condensed Financial Statements under "Southern Company's Sale of Gulf Power" herein for additional information. The ultimate outcome of this matter cannot be determined at this time.
On June 4, 2018, Southern Company Gas completed the stock sale of Pivotal Home Solutions to American Water Enterprises LLC for a total cash purchase price of $358 million and an additional $6 million for working capital. This disposition resulted in a net loss of $76 million, which included $40 million of income tax expense. In contemplation of the transaction, a goodwill impairment charge of $42 million was recorded during the first quarter 2018.
On July 1, 2018, a Southern Company Gas subsidiary, Pivotal Utility Holdings, completed the sales of the assets of two of its natural gas distribution utilities, Elizabethtown Gas and Elkton Gas, to South Jersey Industries, Inc. for a total cash purchase price of $1.7 billion and an additional $40 million for working capital. This disposition resulted in an estimated pre-tax gain of approximately $235 million and an after-tax gain of approximately $12 million, which will be recorded in the third quarter 2018.
On July 29, 2018, Southern Company Gas and its wholly-owned direct subsidiary, NUI Corporation, completed the stock sale of Pivotal Utility Holdings, which primarily consisted of Florida City Gas, to NextEra Energy for a total cash purchase price of $530 million (less $3 million of indebtedness assumed at closing for customer deposits) and an additional $60 million for cash and other working capital. This disposition resulted in an estimated pre-tax gain of approximately $126 million and an after-tax gain of approximately $4 million, which will be recorded in the third quarter 2018.
The after-tax impacts of Southern Company Gas' dispositions included income tax expense on goodwill not deductible for tax purposes and for which a deferred tax liability had not been recorded previously. Additionally, each of these dispositions is subject to a final working capital adjustment that may impact the cash proceeds from disposition, but not the gain recorded. See Note (J) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information on Southern Company Gas' dispositions.
In MayNovember 2018, Southern Power completed the sale of a 33% equity interest in SPSH, a newly-formed limited partnership indirectly owning substantiallyentered into an agreement to sell all of Southern Power's solar facilities,its equity interests in Plant Mankato (including the 385-MW expansion currently under construction) for an aggregate purchase price of approximately $1.2 billion,$650 million. The completion of the disposition is subject to the expansion unit reaching commercial operation as well as various other customary conditions to closing, including FERC and state commission approvals. On April 17, 2019, Southern Power entered into an agreement to sell all of its equity interests in the Nacogdoches biomass-fueled facility to Austin Energy for an aggregate purchase price of $460 million, subject to customary closing conditions and working capital adjustments. Southern Power maintains control and overall operational responsibilities for the solar facilities. See Note (J) to the Condensed Financial Statements under "Southern Power" herein for additional information.
Southern Power is pursuing the saleEach of a noncontrolling interest in a portfolio of eight operating wind facilities through the use of third-party tax equity, which, if successful,these sales is expected to close in mid-2019; however, the fourth quarter 2018. See "Income Tax Matters – Southern Power" herein for additional information. The ultimate outcome of this matterthese matters cannot be determined at this time.
For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Southern Company in Item 7 of the Form 10-K.

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Environmental Matters
The Southern Company system's operations are regulated by state and federal environmental agencies through a variety of laws and regulations governing air, water, land, and protection of other natural resources. The Southern Company system maintains comprehensive environmental compliance and greenhouse gas (GHG)GHG strategies to assess upcoming requirements and compliance costs associated with these environmental laws and regulations. The costs, including capital expenditures, and operations and maintenance costs, and costs reflected in ARO liabilities, required to comply with environmental laws and regulations and to achieve stated goals may impact future electric generating unit retirement and replacement decisions, results of operations, cash flows, andand/or financial condition. Related costs may result from the installation of additional environmental controls, closure and monitoring of CCR facilities, unit retirements, and adding or changing fuel sources for certain existing units, as well as related upgrades to the Southern Company system's transmission system.and distribution (electric and natural gas) systems. A major portion of these costs areis expected to be recovered through existing ratemaking provisions.retail and wholesale rates. The ultimate impact of environmental laws and regulations and the GHG goals discussed below will depend on various factors, such as state adoption and implementation of requirements, the availability and cost of any deployed control technology, 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 fully recovered in rates on a timely basis for the traditional electric operating companies and the natural gas distribution utilities or through long-term wholesale agreements for the traditional electric operating companies and Southern Power. Further, increased costs that are recovered through regulated rates could contribute to reduced demand for electricity and natural gas, which could negatively affect results of operations, cash flows, andand/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 of Southern Company under "Environmental Matters" in Item 8 of the Form 10-K for additional information.
Environmental Laws and Regulations
Water Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Water Quality" of Southern Company in Item 7 of the Form 10-K for additional information regarding the effluent limitations guidelines (ELG) rule.
On May 2, 2018, the EPA updated its anticipated final rulemaking schedule for ELG from September 2020 to December 2019. The impact of any changes to the ELG rule will depend on the content of the final rule and the outcome of any legal challenges and cannot be determined at this time.
Coal Combustion Residuals
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Coal Combustion Residuals" of Southern Company in Item 7 of the Form 10-K for additional information regarding the Disposal of Coal Combustion Residuals from Electric Utilities rule (CCR Rule).
On July 30, 2018, the EPA published certain amendments to the CCR Rule, which will be effective August 29, 2018. These amendments extend the date from April 2019 to October 31, 2020 to cease sending CCR and other waste streams to impoundments that demonstrate compliance with all except two specified criteria. These amendments also establish groundwater protection standards for four constituents that do not have established EPA maximum contaminant levels and allow a participating state director or the EPA (where the EPA is the permitting authority) to suspend groundwater monitoring requirements under certain circumstances. Specific site impacts are being evaluated by the traditional electric operating companies.

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In June 2018, Alabama Power recorded an increase of approximately $1.2 billion to its AROs related to the CCR Rule. The revised cost estimates as of June 30, 2018 are based on information from feasibility studies performed on ash ponds in use at plants operated by Alabama Power, including a plant jointly-owned by Mississippi Power. During the second quarter 2018, Alabama Power's management completed its analysis of these studies which indicated that additional closure costs, primarily related to increases in estimated ash volume, water management requirements, and design revisions, will be required to close these ash ponds under the planned closure-in-place methodology.Regulatory Matters
Georgia Power continues to perform engineering studies related to its plans to close the ash ponds at all of its generating plants, including one jointly owned with Gulf Power, in compliance with federal and state CCR rules. Georgia Power also continues to refine its closure strategy and cost estimates for each ash pond and is preparing permit applications as required by the State of Georgia CCR rule. While Georgia Power believes its recorded liability for ash pond closures appropriately reflects its obligations under the current closure strategies it has elected, changes to such strategies and cost estimates would likely result in additional closure costs which would increase Georgia Power's ARO liability. It is not currently possible to determine the magnitude of an increase related to a change in closure strategies nor an increase related to ongoing engineering studies for the current closure strategies, and the timing of future cash outflows are indeterminable at this time. As permit applications advance, engineering studies continue, and the timing of ash pond closures develop further on a plant-by-plant basis during the second half of 2018 and in the future, Georgia Power will record any changes as necessary to its ARO liability, which could be material. Georgia Power expects to continue to periodically update these cost estimates as necessary, which could change further as additional information becomes available.
As further analysis is performed and closure details are developed with respect to ash pond closures, the traditional electric operating companies expect to periodically update their cost estimates as necessary. Absent continued recovery of ARO costs through regulated rates, Southern Company's results of operations, cash flows, and financial condition could be materially impacted. See Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information.
The ultimate outcome of these matters cannot be determined at this time.
Nuclear Decommissioning
In June 2018, Alabama Power completed an updated decommissioning cost site study for Plant Farley. The estimated cost of decommissioning based on the study resulted in an increase in the ARO liability of approximately $300 million. Amounts previously contributed to Alabama Power's external trust funds are currently projected to be adequate to meet the updated decommissioning obligations. See Note 12 to the financial statements of Southern Company under "Nuclear Decommissioning" in Item 8 of the Form 10-K and Note (A)(B) to the Condensed Financial Statements under "Asset Retirement Obligations" and "Nuclear Decommissioning" herein for additional information.
Global Climate Issues
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues" of Southern Company in Item 7 of the Form 10-K for additional information regarding domestic GHG policies.
Through 2017, the Southern Company system has achieved an estimated GHG emission reduction of 36% since 2007. In April 2018, Southern Company established an intermediate goal of a 50% reduction in carbon emissions from 2007 levels by 2030 and a long-term goal of low- to no-carbon operations by 2050. To achieve these goals, the Southern Company system expects to continue growing its renewable energy portfolio, optimize technology advancements to modernize its transmission and distribution systems, increase the use of natural gas for generation, complete construction of Plant Vogtle Units 3 and 4, invest in energy efficiency, and continue research and development efforts focused on technologies to lower GHG emissions. The Southern Company system's ability to achieve these goals also will be dependent on many external factors, including supportive national energy policies,

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low natural gas prices, and the development, deployment, and advancement of relevant energy technologies. The ultimate outcome of this matter cannot be determined at this time.
FERC Matters
Market-Based Rate Authority
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "FERC Matters Market-Based Rate Authority" of Southern Company in Item 7 of the Form 10-K for additional information regarding proceedings related to the traditional electric operating companies' and Southern Power's 2014 and 2017 triennial market power analyses.
On May 4, 2018, the FERC issued an order terminating both proceedings, finding that the traditional electric operating companies and Southern Power satisfy the FERC's standards for market-based rates. On May 9, 2018, the traditional electric operating companies and Southern Power made the compliance filing required by the order. These proceedings are essentially concluded.
Open Access Transmission Tariff
On May 10, 2018, the Alabama Municipal Electric Authority and Cooperative Energy filed with the FERC a complaint against SCS and the traditional electric operating companies claiming that the current 11.25% base ROE used in calculating the annual transmission revenue requirements of the traditional electric operating companies' open access transmission tariff is unjust and unreasonable as measured by the applicable FERC standards. The complaint requests that the base ROE be set no higher than 8.65% and that the FERC order refunds for the difference in revenue requirements that results from applying a just and reasonable ROE established in this proceeding upon determining the current ROE is unjust and unreasonable. On June 18, 2018, SCS and the traditional electric operating companies filed their response challenging the adequacy of the showing presented by the complainants and offering support for the current ROE. The ultimate outcome of this matter cannot be determined at this time.
Regulatory Matters
Fuel Cost Recovery
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Regulatory Matters Fuel Cost Recovery" of Southern Company in Item 7 and Note 3 to the financial statements of Southern Company under "Regulatory Matters – Alabama Power – Rate ECR" and "Regulatory Matters – Georgia Power – Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information regarding fuel cost recovery for the traditional electric operating companies.
The traditional electric operating companies each have established fuel cost recovery rates approved by their respective state PSCs. Fuel cost recovery revenues are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on Southern Company's revenues or net income, but will affect cash flow. The traditional electric operating companies continuously monitor their under or over recovered fuel cost balances and make appropriate filings with their state PSCs to adjust fuel cost recovery rates as necessary.
Alabama Power
Alabama Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Alabama PSC. Alabama Power currently recovers its costs from the regulated retail business primarily through Rate RSE, Rate CNP, Rate ECR, and Rate NDR. In addition, the Alabama PSC issues accounting orders to address current events impacting Alabama Power.
Environmental Accounting Order
In connection with management's decision to retire Plant Gorgas, in February 2019, Alabama Power reclassified approximately $1.3 billion for Plant Gorgas Unit 10 from plant in service, net of depreciation to other utility plant, net and continued to depreciate the asset according to the original depreciation rates. On April 15, 2019, Alabama Power retired Plant Gorgas Units 8, 9, and 10 and reclassified approximately $740 million of the remaining net investment costs of the units to a regulatory asset to be recovered over the units' remaining useful lives as established prior to the decision to retire. Additionally, approximately $700 million of net capitalized asset retirement costs will be reclassified to a regulatory asset and recovered in accordance with accounting guidance provided by the Alabama PSC. See Note 32 to the financial statements of Southern Company under "Regulatory Matters"Alabama PowerAlabama Power" in Item 8 of the Form 10-KEnvironmental Accounting Order" and Note (B) to the Condensed Financial Statements herein for additional information regarding Alabama Power's rate mechanisms, accounting orders, and the recovery balance of each regulatory clause for Alabama Power.

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On May 1, 2018, the Alabama PSC approved modifications to Rate RSE and other commitments designed to position Alabama Power to address the growing pressure on its credit quality resulting from the Tax Reform Legislation, without increasing retail rates under Rate RSE in the near term. Alabama Power plans to reduce growth in total debt by increasing equity, with corresponding reductions in debt issuances, thereby de-leveraging its capital structure. Alabama Power's goal is to achieve an equity ratio of approximately 55% by the end of 2025. At June 30, 2018, Alabama Power's equity ratio was approximately 46.6%. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Federal Tax Reform Legislation" of Southern Company in Item 7 of the Form 10-K for additional information.
Rate RSE
The approved modifications to Rate RSE became effective June 2018 and are applicable for January 2019 billings and thereafter. The modifications include reducing the top of the allowed weighted common equity return (WCER) range from 6.21% to 6.15% and modifications to the refund mechanism applicable to prior year actual results. The modifications to the refund mechanism allow Alabama Power to retain a portion of the revenue that causes the actual WCER for a given year to exceed the allowed range.
In conjunction with these modifications to Rate RSE, on May 8, 2018, Alabama Power consented to a moratorium on any upward adjustments under Rate RSE for 2019 and 2020. Additionally, Alabama Power will return $50 million to customers through bill credits in 2019.
In accordance with an established retail tariff that provides for an interim adjustment to customer billings to recognize the impact of a change in the statutory income tax rate, Alabama Power is returning approximately $257 million to retail customers through bill credits in the second half of 2018 as a result of the change in the federal income tax rate under the Tax Reform Legislation.
Rate ECR
On May 1, 2018, the Alabama PSC approved an increase to Rate ECR from 2.015 cents per KWH to 2.353 cents per KWH effective July 2018 which is expected to result in additional collections of approximately $100 million through December 31, 2018. The approved increase in the Rate ECR factor will have no significant effect on Southern Company's net income, but will increase operating cash flows related to fuel cost recovery in 2018. The rate will return to 5.910 cents per KWH in 2019, absent a further order from the Alabama PSC.
Accounting Order
On May 1, 2018, the Alabama PSC approved an accounting order that authorizes Alabama Power to defer the benefits of federal excess deferred income taxes associated with the Tax Reform Legislation for the year ending December 31, 2018 as a regulatory liability and to use up to $30 million of such deferrals to offset under recovered amounts under Rate ECR. Any remaining amounts will be used for the benefit of customers as determined by the Alabama PSC. As of June 30, 2018, Alabama Power had applied approximately $30 million of such deferrals to offset the under recovered balance under Rate ECR and expects the total deferrals for the year ending December 31, 2018 to be approximately $50 million. See Note 5 to the financial statements of Southern Company under "Federal Tax Reform Legislation"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 tariffs, and Municipal Franchise Fee tariffs. Georgia Power is scheduled to file a base rate case by July 1, 2019, which may continue or modify these 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.
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 (B) to the Condensed Financial Statements under "Nuclear Construction" herein and Note 36 to the financial statements of Southern Company under "Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding Georgia Power's NCCRinformation.
During the first quarter 2019, Mississippi Power recorded pre-tax charges to income of $2 million ($1 million after tax), 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

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tariff. Also see Note (B) to the Condensed Financial Statements under "Regulatory MattersGeorgia PowerFuel Cost Recovery" herein for additional information regarding Georgia Power's fuel cost recovery.
Rate Plans
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Georgia Power – Rate Plans" of Southern Company in Item 7 of the Form 10-K for additional information regarding Georgia Power's 2013 ARP and the Georgia PSC's 2018 order related to the Tax Reform Legislation.
On April 3, 2018, the Georgia PSC approved a settlement agreement between Georgia Power and the staff of the Georgia PSC regarding the retail rate impact of the Tax Reform Legislation (Georgia Power Tax Reform Settlement Agreement). Pursuant to the Georgia Power Tax Reform Settlement Agreement, to reflect the federal income tax rate reduction impact of the Tax Reform Legislation, Georgia Power will refund to customers a total of $330 million through bill credits of $131 million in October 2018, $96 million in June 2019, and $103 million in February 2020. In addition, Georgia Power is deferring as a regulatory liability (i) the revenue equivalent of the tax expense reduction resulting from legislation lowering the Georgia state income tax rate from 6.00% to 5.75% in 2019 and (ii) the entire benefit of approximately $700 million in federal and state excess accumulated deferred income taxes. The amortization of these regulatory liabilities is expected to be addressed in Georgia Power's next base rate case, which is scheduled to be filed by July 1, 2019. If there is not a base rate case in 2019, customers will receive $185 million in annual bill credits beginning in 2020, with any additional federal and state income tax savings deferred as a regulatory liability, until Georgia Power's next base rate case.
To address the negative cash flow and credit metric impacts of the Tax Reform Legislation, the Georgia PSC also approved an increase in Georgia Power's retail equity ratio to the lower of (i) Georgia Power's actual common equity weight in its capital structure or (ii) 55%, until Georgia Power's next base rate case. Benefits from reduced federal income tax rates in excess of the amounts refunded to customers will be retained by Georgia Power to cover the carrying costs of the incremental equity in 2018 and 2019.
Gulf Power
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Gulf Power" of Southern Company in Item 7 of the Form 10-K for additional information.
As a continuation of the 2017 Gulf Power Rate Case Settlement Agreement, on March 26, 2018, the Florida PSC approved a stipulation and settlement agreement among Gulf Power and three intervenors addressing the retail revenue requirement effects of the Tax Reform Legislation (Gulf Power Tax Reform Settlement Agreement).
The Gulf Power Tax Reform Settlement Agreement results in annual reductions to Gulf Power's revenues of $18.2 million from base rates and $15.6 million from environmental cost recovery rates, implemented April 1, 2018, and also provides for a one-time refund of $69.4 million for the retail portion of unprotected (not subject to normalization) deferred tax liabilities through a reduced fuel cost recovery rate over the remainder of 2018. Through June 30, 2018, approximately $28 million of this refund has been reflected in customer bills. As a result of the Gulf Power Tax Reform Settlement Agreement, the Florida PSC also approved an increase in Gulf Power's maximum equity ratio from 52.5% to 53.5% for all retail regulatory purposes.
As part of the Gulf Power Tax Reform Settlement Agreement, a limited scope proceeding to address protected deferred tax liabilities consistent with IRS normalization principles was initiated on April 30, 2018. Pending resolution of this proceeding, Gulf Power is deferring the related amounts for 2018 as a regulatory liability. Through June 30, 2018, amounts deferred totaled $5 million. Unless otherwise agreed to by the parties to the Gulf Power Tax Reform Settlement Agreement, amounts recorded in this regulatory liability will be refunded to retail customers in 2019 through Gulf Power's fuel cost recovery rates. The ultimate outcome of this matter cannot be determined at this time.

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Mississippi Power
On February 7, 2018, Mississippi Power submitted its revised 2018 projected PEP filing to the Mississippi PSC, which reflected the impacts of the Tax Reform Legislation, requesting an increase in annual retail revenues of $26 million based on a performance adjusted ROE of 9.33% and an increased equity ratio of 55%.
On July 27, 2018, Mississippi Power and the Mississippi Public Utilities Staff (MPUS) entered into a settlement agreement with respect to the 2018 PEP filing and all unresolved PEP filings for prior years (PEP Settlement Agreement), which was approved by the Mississippi PSC on August 7, 2018. Rates under the PEP Settlement Agreement will take effect for the first billing cycle of September 2018.
The PEP Settlement Agreement provides for an increase of approximately $21.6 million in annual base retail revenues, which excludes approximately $5.5 million requested for certain compensation costs contested by the MPUS. Under the PEP Settlement Agreement, Mississippi Power expects to defer these costs for 2018 and 2019 as a regulatory asset. The Mississippi PSC is currently expected to rule on the appropriate treatment for such costs in connection with Mississippi Power's next base rate case, which is scheduled to be filed in the fourth quarter 2019 (2019 Base Rate Case). The ultimate outcome of this matter cannot be determined at this time.
Pursuant to the PEP Settlement Agreement, Mississippi Power's performance-adjusted allowed ROE will be 9.31% and its allowed equity ratio will remain at 50%, pending further review by the Mississippi PSC. In lieu of the requested equity ratio increase, Mississippi Power will retain $44 million of excess accumulated deferred income taxes resulting from the Tax Reform Legislation, which had been proposed to be amortized beginning in 2018, until the conclusion of the 2019 Base Rate Case. Further, Mississippi Power will seek equity contributions sufficient to restore its equity ratio (which was 43.5% at June 30, 2018) to the 50% target. In the event Mississippi Power's actual average equity ratio for 2018 is more than 1% higher or lower than the 50% target, Mississippi Power will defer the corresponding difference in its revenue requirement as a regulatory asset or liability for resolution in the 2019 Base Rate Case.
Pursuant to the PEP Settlement Agreement, PEP proceedings will be suspended until after the conclusion of the 2019 Base Rate Case and Mississippi Power will not be required to make any PEP filings for regulatory years 2018, 2019, and 2020. The PEP Settlement Agreement also resolves all open PEP filings with no change to customer rates. As a result, in the third quarter 2018, Mississippi Power expects to recognize revenues of $5 million previously reserved in connection with the 2012 PEP lookback filing.
Southern Company Gas
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters – Southern Company Gas" of Southern Company in Item 7 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory MattersSouthern Company Gas" herein for additional information.
On February 23, 2018, Atlanta Gas Light revised its annual base rate filing to reflect the impacts of the Tax Reform Legislation and requested a $16 million rate reduction in 2018. On May 15, 2018, the Georgia PSC approved a stipulation for Atlanta Gas Light's annual base rates to remain at the 2017 level for 2018 and 2019, with customer credits of $8 million in each of July 2018 and October 2018 to reflect the impacts of the Tax Reform Legislation. The Georgia PSC maintained Atlanta Gas Light's previously authorized earnings band based on a ROE between 10.55% and 10.95% and increased the allowed equity ratio by 4% to an equity ratio of 55% to address the negative cash flow and credit metric impacts of the Tax Reform Legislation. Additionally, Atlanta Gas Light is required to file a traditional base rate case on or before June 1, 2019 for rates effective January 1, 2020.
On May 2, 2018, the Illinois Commission approved Nicor Gas' rehearing request for revised base rates to incorporate the reduction in the federal income tax rate as a result of the Tax Reform Legislation. The resulting decrease of approximately $44 million in annual base rate revenues became effective May 5, 2018. Nicor Gas' previously-authorized capital structure and ROE of 9.8% were not addressed in the rehearing and remain unchanged.

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Kemper County Energy Facility
For additional information on the Kemper County energy facility, see Note 3 to the financial statements of Southern Company under "Kemper County Energy Facility" in Item 8 of the Form 10-K.
As the mining permit holder for the Kemper County energy facility, Liberty Fuels Company, LLC has a legal obligation to perform mine reclamation, and Mississippi Power has a contractual obligation to fund all reclamation activities. Mine reclamation began in the first quarter 2018.
As of June 30, 2018, Mississippi Power recorded charges to income of an immaterial amount for the second quarter 2018 and $45 million ($33 million after tax) for year-to-date 2018, primarily resulting from the abandonment and related closure activities for the mine and gasifier-related assets at the Kemper County energy facility. Additional closure costs for the mine and gasifier-related assets, currently estimated to costat up to $25$10 million pre-tax (excluding salvage, net of dismantlement costs), are expected tomay be incurred duringthrough the remainderfirst half of 2018 and 2019.2020. 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 $4$11 million for the remainder of 2018, $7 million in 2019 and $4$2 million to $6 million annually beginning in 2020.2020 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 of an investigation related to the Kemper County energy facility. The ultimate outcome of these matters cannot be determined at this mattertime; 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 within the statutory time limit of 11 months from the filing of the rate case, after which rate adjustments will be effective.
Atlanta Gas Light is required to file a traditional base rate case no later than June 3, 2019 for rates effective January 1, 2020.
The ultimate outcome of these matters cannot be determined at this time.
The combined cycle and associated common facilities portions
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Table of the Kemper County energy facility were dedicated as Plant Ratcliffe on April 27, 2018.Contents
Reserve Margin PlanSOUTHERN COMPANY AND SUBSIDIARY COMPANIES
On August 6, 2018, Mississippi Power filed its proposed Reserve Margin Plan (RMP), as required by the Mississippi PSC's order in the docket established for the purposes of pursuing a global settlement of the costs related to the Kemper County energy facility. Under the RMP, Mississippi Power proposes alternatives that would reduce its reserve margin, with the most economic of the alternatives being the 2-year and 7-year acceleration of the retirement of Plant Watson Units 4 and 5, respectively, to the first quarter 2022 and the 4-year acceleration of the retirement of Plant Greene County Units 1 and 2 to the third quarter 2021 and the third quarter 2022, respectively, in order to lower or avoid operating costs. The Plant Greene County unit retirements would require the completion by Alabama Power of proposed transmission and system reliability improvements, as well as agreement by Alabama Power. The RMP filing also states that, in the event the Mississippi PSC ultimately approves an alternative that includes an accelerated retirement, Mississippi Power would require authorization to defer in a regulatory asset for future recovery the remaining net book value of the units at the time of retirement. Mississippi Power expects the MPUS and other interested parties to review the proposal prior to resolution by the Mississippi PSC. The ultimate outcome of this matter cannot be determined at this time. However, if approved by the Mississippi PSC, the alternatives are not expected to have any adverse impact on customer rates.MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Construction ProgramRegulatory Matters
OverviewSee 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 subsidiary companies of Southern Company are engaged in continuous construction programs to accommodate existing and estimated future loads on their respective systems. The Southern Company system intends to continue its strategy of developing and constructing new electric generating facilities, adding environmental modifications to certain existing units, expanding the electric transmission and distribution systems, and updating and expanding the natural gas distribution systems. For the traditional electric operating companies major generation construction projectseach 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 statethe 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 approvalissues accounting orders to address current events impacting Alabama Power.
Environmental Accounting Order
In connection with management's decision to retire Plant Gorgas, in orderFebruary 2019, Alabama Power reclassified approximately $1.3 billion for Plant Gorgas Unit 10 from plant in service, net of depreciation to other utility plant, net and continued to depreciate the asset according to the original depreciation rates. On April 15, 2019, Alabama Power retired Plant Gorgas Units 8, 9, and 10 and reclassified approximately $740 million of the remaining net investment costs of the units to a regulatory asset to be includedrecovered over the units' remaining useful lives as established prior to the decision to retire. Additionally, approximately $700 million of net capitalized asset retirement costs will be reclassified to a regulatory asset and recovered in retail rates. While Southern Power generally constructs and acquires generation assets coveredaccordance with accounting guidance provided 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.Alabama PSC. See Notes 3 and 12Note 2 to the financial statements under "Alabama Power – Environmental Accounting Order" and Note 6 in Item 8 of Southernthe Form 10-K for additional information.
Georgia Power
Georgia Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Georgia PSC. Georgia Power currently recovers its costs from the regulated retail business through the 2013 ARP, which includes traditional base tariff rates, Demand-Side Management tariffs, Environmental Compliance Cost Recovery tariffs, and Municipal Franchise Fee tariffs. Georgia Power is scheduled to file a base rate case by July 1, 2019, which may continue or modify these 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.
Mississippi Power
Kemper County Energy Facility
As the mining permit holder, Liberty Fuels Company, under "Regulatory Matters – Southern Company Gas – RegulatoryLLC 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 first quarter 2019, Mississippi Power recorded pre-tax charges to income of $2 million ($1 million after tax), 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

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Infrastructure Programs"the mine and "Southerngasifier-related assets, currently estimated at up to $10 million pre-tax (excluding salvage, net of dismantlement costs), 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 $11 million for the remainder of 2019 and $2 million to $6 million annually in 2020 through 2023.
In addition, Mississippi Power – Construction Projectsconstructed the CO2 pipeline for the planned transport of captured CO2 for use in Progress," respectively, in Item 8enhanced oil recovery and is currently evaluating its options regarding the final disposition of the Form 10-K and Note (J)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 Condensed Financial Statements under "Southern$387 million of grants received. Mississippi Power" herein for additional information.
The largest construction project and the DOE are currently underway in discussions regarding the Southern Company system is Plant Vogtle Units 3requested closeout and 4 (45.7% ownership interest by Georgia Power in the two units, each with approximately 1,100 MWs). See Note 3property disposition, which may require payment to the financial statementsDOE for a portion of Southern Company under "Nuclear Construction" in Item 8 of the Form 10-K and "Nuclear Construction" herein for additional information.
Also see FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein for additional information regarding Southern Company's capital requirements for its subsidiaries' construction programs.
Nuclear Construction
See Note 3certain property that is to the financial statements of Southern Company under "Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding the construction of Plant Vogtle Units 3 and 4, VCM reports, and the NCCR tariff.
In 2009, the Georgia PSC certified construction of Plant Vogtle Units 3 and 4. In 2012, the NRC issued the related combined construction and operating licenses, which allowed full construction of the two AP1000 nuclear units (with electric generating capacity of approximately 1,100 MWs each) and related facilities to begin. Until March 2017, construction on Plant Vogtle Units 3 and 4 continued under the Vogtle 3 and 4 Agreement, which was a substantially fixed price agreement. In March 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code.
be retained by Mississippi Power. In connection with the EPC Contractor's bankruptcy filing, GeorgiaDOE closeout discussions, on April 29, 2019, the Civil Division of the Department of Justice informed Southern Company and Mississippi Power acting for itselfof 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 as agentoversight by their respective state regulatory agencies for the Vogtle Owners, entered intorates charged to their customers and other matters. With the Interim Assessment Agreementexception 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 EPC Contractor to allow construction to continue.Illinois Commission requesting a $230 million increase in annual base rate revenues. The Interim Assessment Agreement expired in July 2017 when Georgia Power, acting for itself and as agentrequested increase is based on a projected test year for the other Vogtle Owners,12-month period ending September 30, 2020, a ROE of 10.6%, and an increase in the EPC Contractor entered intoequity ratio from 52% to 54% to address the Vogtle Services Agreement. Undernegative cash flow and credit metric impacts of the Vogtle Services Agreement, Westinghouse provides facility design and engineering services, procurement and technical support, and staff augmentation on a time and materials cost basis. The Vogtle Services Agreement will continue until the start-up and testing of Plant Vogtle Units 3 and 4 are complete and electricity is generated and sold from both units. The Vogtle Services Agreement is terminable by the Vogtle Owners upon 30 days' written notice.Tax Reform Legislation.
In October 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners,On April 16, 2019, Nicor Gas entered into a construction completionstipulation agreement to resolve all related issues with Bechtel, whereby Bechtel will serve as the primary contractor forStaff 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 construction activities for Plant Vogtle Units 3items outstanding with the other two intervenors. As a result of the stipulation agreement and 4 (Bechtel Agreement). rebuttal testimony, the revised requested annual revenue increase is $180 million.
The Bechtel AgreementIllinois Commission is a cost reimbursable plus fee arrangement, whereby Bechtel is reimbursed for actual costs plus a base fee and an at-risk fee,expected to rule on the requested increase within the statutory time limit of 11 months from the filing of the rate case, after 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 Ownersrate adjustments will be required to pay amounts related to work performed prior to the termination (including the applicable portion of the base fee), certain termination-related costs, and, at certain stages of the work, the applicable portion of the at-risk fee. Bechtel may terminate the Bechtel Agreement under certain circumstances, including certain Vogtle Owner suspensions of work, certain breaches of the Bechtel Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events. Pursuant to the Loan Guarantee Agreement between Georgia Power and the DOE, Georgia Powereffective.
Atlanta Gas Light is required to obtain the DOE's approvalfile a traditional base rate case no later than June 3, 2019 for rates effective January 1, 2020.
The ultimate outcome of the Bechtel Agreement prior to obtaining any further advances under the Loan Guarantee Agreement.
In December 2017, the Georgia PSC approved Georgia Power's seventeenth VCM report, which included a recommendation to continue construction of Plant Vogtle Units 3 and 4, with Southern Nuclear serving as project manager and Bechtel serving as the primary construction contractor.these matters cannot be determined at this time.

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Cost and Schedule
In preparation for its nineteenth VCM filing, Georgia Power requested Southern Nuclear to perform a full cost reforecast for the project. Georgia Power's approximate proportionate share of the remaining estimated capital cost to complete Plant Vogtle Units 3 and 4 by the expected in-service dates of November 2021 and November 2022, respectively, is as follows:
 (in billions)
Base project capital cost forecast(a)(b)
$8.0
Construction contingency estimate0.4
Total project capital cost forecast(a)(b)
8.4
Net investment as of June 30, 2018(b)
(4.0)
Remaining estimate to complete(a)
$4.4
(a)Excludes financing costs expected to be capitalized through AFUDC of approximately $350 million.
(b)Net of $1.7 billion received from Toshiba in 2017 under the Guarantee Settlement Agreement and $188 million in Customer Refunds recognized as a regulatory liability in 2017.
Georgia Power estimates that its financing costs for construction of Plant Vogtle Units 3 and 4 will total approximately $3.2 billion, of which $1.7 billion had been incurred through June 30, 2018.
The $0.7 billion increase to the base capital cost forecast reflected in the table above primarily results from changed assumptions related to the finalization of contract scopes and management responsibilities for Bechtel and over 60 subcontractors, labor productivity rates, and craft labor incentives, as well as the related levels of project management, oversight, and support, including field supervision and engineering support.
Although Georgia Power believes these incremental costs are reasonable and necessary to complete the project and the Georgia PSC's order in the seventeenth VCM proceeding specifically states that the construction of Plant Vogtle Units 3 and 4 is not subject to a cost cap, Georgia Power does not intend to seek rate recovery for these cost increases included in the current base capital cost forecast (or any related financing costs), which will be filed with the Georgia PSC in the nineteenth VCM report at the end of August 2018. In connection with future VCM filings, Georgia Power may request the Georgia PSC to evaluate costs currently included in the construction contingency estimate for rate recovery as and when they are appropriately included in the base capital cost forecast. After considering the significant level of uncertainty that exists regarding the future recoverability of costs included in the construction contingency estimate since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in these future regulatory proceedings, Georgia Power has recorded a total pre-tax charge to income of $1.1 billion ($0.8 billion after tax), which includes the total increase in the capital cost forecast and construction contingency estimate as of June 30, 2018.
Subsequent to the EPC Contractor bankruptcy filing, a number of subcontractors to the EPC Contractor alleged non-payment by the EPC Contractor for amounts owed for work performed on Plant Vogtle Units 3 and 4. Georgia Power, acting for itself and as agent for the Vogtle Owners, has taken actions to remove liens filed by these subcontractors through the posting of surety bonds. Related to such liens, certain subcontractors have filed, and additional subcontractors may file, lawsuits against the EPC Contractor and the Vogtle Owners to preserve their payment rights with respect to such claims. All known amounts associated with the removal of subcontractor liens and other EPC Contractor pre-petition accounts payable have been paid or accrued as of June 30, 2018. The ultimate liability is expected to be finalized in connection with the completion of the sale of Westinghouse.
As construction continues, challenges with management of contractors, subcontractors, and vendors; labor productivity, availability, and/or cost escalation; procurement, fabrication, delivery, assembly, and/or installation, including any required engineering changes, of plant systems, structures, and components (some of which are based on new technology that is just beginning initial operation in the global nuclear industry at this scale); or other issues could arise and change the projected schedule and estimated cost.

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There have been technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4 at the federal and state level and additional challenges may arise. Processes are in place that are designed to assure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating licenses, including inspections by Southern Nuclear and the NRC that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the NRC. Various design and other licensing-based compliance matters, including the timely resolution of Inspections, Tests, Analyses, and Acceptance Criteria and the related approvals by the NRC, may arise, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs.
The ultimate outcome of these matters cannot be determined at this time. However, any extension of the project schedule is currently estimated to result in additional base capital costs of approximately $50 million per month, based on Georgia Power's ownership interests, and AFUDC of approximately $12 million per month. While Georgia Power is not precluded from seeking recovery of any future capital cost forecast increase, management will ultimately determine whether or not to seek recovery. Any further changes to the capital cost forecast that are not expected to be recoverable through regulated rates will be required to be charged to income and such charges could be material.
Joint Owner Contracts
In November 2017, the Vogtle Owners entered into an amendment to their joint ownership agreements for Plant Vogtle Units 3 and 4 (as amended, Vogtle Joint Ownership Agreements) to provide for, among other conditions, additional Vogtle Owner approval requirements. Pursuant to the Vogtle Joint Ownership Agreements, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction if certain adverse events occur, including: (i) the bankruptcy of Toshiba; (ii) termination or rejection in bankruptcy of certain agreements, including the Vogtle Services Agreement or the Bechtel Agreement; (iii) the Georgia PSC or Georgia Power determines that any of Georgia Power's costs relating to the construction of Plant Vogtle Units 3 and 4 will not be recovered in retail rates because such costs are deemed unreasonable or imprudent; or (iv) an increase in the construction budget contained in the seventeenth VCM report of more than $1 billion or extension of the project schedule contained in the seventeenth VCM report of more than one year. In addition, pursuant to the Vogtle Joint Ownership Agreements, the required approval of holders of ownership interests in Plant Vogtle Units 3 and 4 is at least (i) 90% for a change of the primary construction contractor and (ii) 67% for material amendments to the Vogtle Services Agreement or agreements with Southern Nuclear or the primary construction contractor, including the Bechtel Agreement. The Vogtle Joint Ownership Agreements also confirm that the Vogtle Owners' sole recourse against Georgia Power or Southern Nuclear for any action or inaction in connection with their performance as agent for the Vogtle Owners is limited to removal of Georgia Power and/or Southern Nuclear as agent, except in cases of willful misconduct.
As a result of the increase in the total project capital cost forecast and Georgia Power's decision not to seek rate recovery of the increase in the base capital costs as described in "Cost and Schedule" herein, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction. The Vogtle Owners are expected to conduct these votes in the third quarter 2018.
If the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 do not vote to continue construction, the Vogtle Joint Ownership Agreements provide that the project will be cancelled, and construction will cease. In the event that fewer than 90% of the Vogtle Owners vote to continue construction, Georgia Power and the other Vogtle Owners will assess options for Plant Vogtle Units 3 and 4. If Plant Vogtle Units 3 and 4 were cancelled and Georgia Power was unable to recover costs it has incurred in connection with the project, Southern Company's results of operations, cash flow, and financial condition would be materially impacted. The ultimate outcome of this matter cannot be determined at this time.

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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
In connection with management's decision to retire Plant Gorgas, in February 2019, Alabama Power reclassified approximately $1.3 billion for Plant Gorgas Unit 10 from plant in service, net of depreciation to other utility plant, net and continued to depreciate the asset according to the original depreciation rates. On April 15, 2019, Alabama Power retired Plant Gorgas Units 8, 9, and 10 and reclassified approximately $740 million of the remaining net investment costs of the units to a regulatory asset to be recovered over the units' remaining useful lives as established prior to the decision to retire. Additionally, approximately $700 million of net capitalized asset retirement costs will be reclassified to a regulatory asset and recovered in accordance with accounting guidance provided by the Alabama PSC. 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 tariffs, and Municipal Franchise Fee tariffs. Georgia Power is scheduled to file a base rate case by July 1, 2019, which may continue or modify these 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.
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 first quarter 2019, Mississippi Power recorded pre-tax charges to income of $2 million ($1 million after tax), 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

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the mine and gasifier-related assets, currently estimated at up to $10 million pre-tax (excluding salvage, net of dismantlement costs), 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 $11 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 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 within the statutory time limit of 11 months from the filing of the rate case, after which rate adjustments will be effective.
Atlanta Gas Light is required to file a traditional base rate case no later than June 3, 2019 for rates effective January 1, 2020.
The ultimate outcome of these matters cannot be determined at this time.

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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 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

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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.
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 estimate0.4
Total project capital cost forecast(a)(b)
8.4
Net investment as of March 31, 2019(b)
(4.9)
Remaining estimate to complete(a)
$3.5
(a)Excludes financing costs expected to be capitalized through AFUDC of approximately $325 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 $1.9 billion had been incurred through March 31, 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 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.
As construction continues, 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), any of which may require additional labor and/or materials; or other issues could arise and change the projected schedule and estimated cost. Monthly construction production targets established as part of a strategy to maintain and build margin to the approved in-service dates will continue to increase significantly throughout 2019. To meet these increasing monthly targets, existing craft construction productivity must improve and additional craft laborers 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 resolution of ITAAC and the related approvals by the NRC, may arise, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs.

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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) 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. As of June 30, 2018,At March 31, 2019, Georgia Power had recovered approximately $1.7$1.9 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) certain recommendations made by Georgia Power in thePower's seventeenth VCM report and modifyingmodified 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 unitUnit is commercially operational. The ROE reductions negatively impacted earnings by approximately $25$100 million in 20172018 and are estimated to have negative earnings impacts of approximately $100$75 million in 20182019 and an aggregate of $585approximately $635 million from 20192020 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

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On February 12, 2018,related to Georgia Interfaith Power & Light, Inc. and Partnership for Southern Equity, Inc.Power's portion of an administrative claim filed a petition appealingin the Georgia PSC's January 11, 2018 order withWestinghouse bankruptcy proceedings. Through the Fulton County Superior Court. On March 8, 2018, Georgia Watch filed a similar appeal tonineteenth VCM, the Fulton County Superior Court for judicial review of the Georgia PSC's final decision and denial of Georgia Watch's motion for reconsideration. Georgia Power believes the two appeals have no merit; however, an adverse outcome in either appeal could have a material impact on Southern Company's results of operations, financial condition, and liquidity.
The Georgia PSC has approved seventeen VCM reports covering the periods through June 30, 2017, including total construction capital costs incurred through that dateJune 30, 2018 of $4.4 billion. On August 21, 2018, the Georgia PSC is scheduled to vote on Georgia Power's eighteenth VCM report, which requested approval of $448 million of construction capital costs (excluding the$5.4 billion (before $1.7 billion of payments received from Toshiba under the Guarantee Settlement Agreement and theapproximately $188 million in related Customer Refunds recognized as a regulatory liability) incurred from July 1, 2017 through December 31, 2017.
On August 31, 2018, Georgia Power will file its nineteenth VCM report withRefunds). In addition, the staff of the Georgia PSC which will reflectrequested, and Georgia Power agreed, to report the revised capitalresults of the cost forecast discussed previously and request approval of $578 million of construction capital costs incurred from Januaryschedule validation process to the Georgia PSC (which is expected to occur by May 1, 2018 through June 30, 2018.2019) and to file its twentieth VCM report concurrently with the twenty-first VCM report by August 31, 2019.
The ultimate outcome of these matters cannot be determined at this time.
See RISK FACTORS of Southern Company in Item 1A herein and of the Form 10-K for a discussion of certain risks associated with the licensing, construction, and operation of nuclear generating units, including potential impacts that could result from a major incident at a nuclear facility anywhere in the world.
DOE Financing
As of June 30, 2018,At March 31, 2019, Georgia Power had borrowed $2.6$3.46 billion related to Plant Vogtle Units 3 and 4 costs as provided through the Amended and Restated Loan Guarantee Agreement and arelated multi-advance credit facilityfacilities among Georgia Power, the DOE, and the FFB, which providesprovide for borrowings of up to $3.46approximately $5.130 billion, subject to the satisfaction of certain conditions. In September 2017, the DOE issued a conditional commitment to Georgia Power for up to approximately $1.67 billion in additional guaranteed loans under the Loan Guarantee Agreement. In June 2018, the DOE approved a request by Georgia Power to extend the conditional commitment to September 30, 2018. Any further extension must be approved by the DOE. Final approval and issuance of these additional loan guarantees by the DOE cannot be assured and are subject to the negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions, including the Vogtle Owners' votes to continue construction. See Note 68 to the financial statements of Southern Company under "DOE"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, (including any decision not to continue construction of Plant Vogtle Units 3 and 4), and conditions to borrowing.
The ultimate outcome of these matters cannot be determined at this time.
Income TaxOther Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Income Tax "Other Matters" of Southern Company in Item 7 of the Form 10-K and FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk," Note (B) to the Condensed Financial Statements under "Regulatory Matters," and Note (H) to the Condensed Financial Statements herein for information regarding the Tax Reform Legislation and related regulatory actions.
Southern Power
In March 2018, Southern Power substantially completed a legal entity reorganization of various direct and indirect subsidiaries that own and operate substantially all of its solar facilities, including certain subsidiaries owned in partnership with various third parties. The reorganization resulted in net state tax benefits related to certain changes

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in apportionment rates totaling approximately $50 million, which were recorded in the first quarter 2018. In April 2018, Southern Power completed the final stage of the reorganization resulting in additional net state tax benefits of approximately $4 million.
Southern Power is pursuing the sale of a noncontrolling interest in a portfolio of eight operating wind facilities through the use of third-party tax equity, which, if successful, is expected to close in the fourth quarter 2018. In the third quarter 2018, various direct and indirect subsidiaries of Southern Power that own and operate these wind facilities are expected to be reorganized under a new holding company in which the tax equity partner would invest. The reorganization is expected to result in estimated net state tax benefits totaling approximately $10 million related to certain changes in apportionment rates. The ultimate outcome of this matter cannot be determined at this time.
Other Mattersinformation.
Southern Company and its subsidiaries are involved in various other matters being litigated and regulatory matters that could affect future earnings.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, or regulatory matters, or potential asset impairments cannot be predicted at this time; however, for current proceedings not specifically reported in NoteNotes (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 NoteNotes (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 2016, a complaint against Mississippi Power was filed in Harrison County Circuit Court (Circuit Court) by Biloxi Freezing & Processing Inc., Gulfside Casino Partnership, and John Carlton Dean, which was amended and refiled to include, among other things, Southern Company as a defendant. The individual plaintiff alleged that Mississippi Power and Southern Company violated the Mississippi Unfair Trade Practices Act. All plaintiffs alleged that Mississippi Power and Southern Company concealed, falsely represented, and failed to fully disclose important facts concerning the cost and schedule of the Kemper County energy facility and that these alleged breaches unjustly enriched Mississippi Power and Southern Company. The plaintiffs sought unspecified actual damages and punitive damages; asked the Circuit Court to appoint a receiver to oversee, operate, manage, and otherwise control all affairs relating to the Kemper County energy facility; asked the Circuit Court to revoke any licenses or certificates authorizing Mississippi Power or Southern Company to engage in any business related to the Kemper County energy facility in Mississippi; and sought attorney's fees, costs, and interest. The plaintiffs also sought an injunction to prevent any Kemper County energy facility costs from being charged to customers through electric rates. In June 2017, the Circuit Court ruled in favor of motions by Southern Company and Mississippi Power and dismissed the case. In July 2017, the plaintiffs filed notice of an appeal. On July 13, 2018, Mississippi Power and Southern Company reached a settlement agreement with the plaintiffs and the plaintiffs' appeal was dismissed with prejudice. The settlement had no material impact on Southern Company's financial statements.
In January 2017, a putative securities class action complaint was filed against Southern Company, certain of its officers, and certain former Mississippi Power officers in the U.S. District Court for the Northern District of Georgia Atlanta Division, by Monroe County Employees' Retirement System on behalf of all persons who purchased shares of Southern Company's common stock between April 25, 2012 and October 29, 2013. The complaint alleges that Southern Company, certain of its officers, and certain former Mississippi Power officers made materially false and

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made materially false and misleading statements regarding the Kemper County energy facility in violation of certain provisions under the Securities Exchange Act of 1934, as amended. The complaint seeks, among other things, compensatory damages and litigation costs and attorneys' fees. In June 2017, the plaintiffs filed an amended complaint that provided additional detail about their claims, increased the purported class period by one day, and added certain other former Mississippi Power officers as defendants. In JulyAlso in 2017, the defendants filed a motion to dismiss the plaintiffs' amended complaint with prejudice, to which the plaintiffs filed an opposition in September 2017. Onopposition. In March 29, 2018, the U.S. District Court for the Northern District of Georgia, Atlanta Division,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. OnIn April 26, 2018, the defendants filed a motion for reconsideration of the court's order, seeking dismissal of the remaining claims in the lawsuit. In 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 and, in May 2017, Judy Mesirov filed a shareholder derivative lawsuit, each in the U.S. District Court for the Northern District of Georgia. Each of these lawsuits names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. In August 2017, these two shareholder derivative lawsuits were consolidated in the U.S. District Court for the Northern District of Georgia. The complaints allege that the defendants caused Southern Company to make false or misleading statements regarding the Kemper County energy facility cost and schedule. Further, the complaints allege that the defendants were unjustly enriched and caused the waste of corporate assets and also allege that the individual defendants violated their fiduciary duties. Each plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and, on each plaintiff's own behalf, attorneys' fees and costs in bringing the lawsuit. Each plaintiff also seeks certain changes to Southern Company's corporate governance and internal processes. OnIn April 25, 2018, the court entered an order staying this lawsuit until 30 days after the resolution of any dispositive motions or any settlement, whichever is earlier, in the putative securities class action.
In May 2017, Helen E. Piper Survivor's Trust filed a shareholder derivative lawsuit in the Superior Court of Gwinnett County, State of Georgia that names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. The complaint alleges that the individual defendants, among other things, breached their fiduciary duties in connection with schedule delays and cost overruns associated with the construction of the Kemper County energy facility. The complaint further alleges that the individual defendants authorized or failed to correct false and misleading statements regarding the Kemper County energy facility schedule and cost and failed to implement necessary internal controls to prevent harm to Southern Company. The plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and disgorgement of profits and, on its behalf, attorneys' fees and costs in bringing the lawsuit. The plaintiff also seeks certain unspecified changes to Southern Company's corporate governance and internal processes. TheIn 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.
OnIn May 18, 2018, Southern Company and Mississippi Power received a notice of dispute and arbitration demand filed by Martin Product Sales, LLC (Martin) based on two agreements, both related to Kemper IGCC byproducts for which Mississippi Power provided termination notices in September 2017. Martin alleges breach of contract, breach of good faith and fair dealing, fraud and misrepresentation, and civil conspiracy and makes a claim for damages in the amount of approximately $143 million, as well as additional unspecified damages, attorney's fees, costs, and interest. In the first quarter 2019, Mississippi Power and Southern Company filed motions to dismiss.
Southern Company believes these legal challenges have no merit; however, an adverse outcome in any of these proceedings could have an impact on Southern Company's results of operations, financial condition, and liquidity. Southern Company will vigorously defend itself in these matters, theThe ultimate outcome of whichthese 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

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Investments in Leveraged Leases
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Other Matters – Investments in Leveraged Leases" of Southern Company in Item 7 and Note 1 to the financial statements of Southern Company under "Leveraged Leases" in Item 8Power that Gulf Power will retire its share of the Form 10-Kgenerating capacity of Plant Daniel on January 15, 2024. Mississippi Power has the option to purchase Gulf Power's ownership interest for additional information regarding a Southern Company Holdings Inc. (Southern Holdings) subsidiary's leveraged lease agreements$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 concerns about the financial and operational performanceeconomic effects of one of the lessees and the associated generation assets.
The ability of the lessees to make required payments to the Southern Holdings subsidiary is dependent on the operational performance of the assets. As a result of operational improvements in the first half of 2018, the June 2018 lease payment was paid in full and the December 2018 lease payment is currently expected to be paid in full. However, operational issues and the resulting cash liquidity challenges persist and significant concerns continue regarding the lessee's ability to make the remaining semi-annual lease payments. These operational challenges may also impact the expected residual value of the assets at the end of the lease term in 2047. If any future lease payment is not paid in full, the Southern Holdings subsidiary may be unable to make its corresponding payment to the holders of the underlying non-recourse debt related to the generation assets. Failure to make the required payment to the debtholders would represent an event of default that would give the debtholders the right to foreclose on, and take ownership of, the generation assets from the Southern Holdings subsidiary, in effect terminating the lease and resulting in the write-off of the related lease receivable, which would result in a reduction in net income of approximately $86 million after tax based on the lease receivable balance as of June 30, 2018. Southern Company has evaluated the recoverability of the lease receivable and the expected residual value of the generation assets at the end of the lease under various scenarios and has concluded that its investment in the leveraged lease is not impaired as of June 30, 2018. Southern Company will continue to monitor the operational performance of the underlying assets and evaluate the ability of the lessee to continue to make the required lease payments.Gulf Power's notice. The ultimate outcome of this matterthese 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.
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 NoteNotes 1, 5, and 6 to the financial statements of Southern Company in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Southern Company's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Southern Company in Item 7 of the Form 10-K for a complete discussion of Southern Company's critical accounting policies and estimates.
Estimated Cost, Schedule, and Rate Recovery for the Construction of Plant Vogtle Units 3 and 4
In December 2016, the Georgia PSC approved the Vogtle Cost Settlement Agreement, which resolved certain prudency matters in connection with Georgia Power's fifteenth VCM report. In December 2017, the Georgia PSC approved Georgia Power's seventeenth VCM report, which included a recommendation to continue construction of Plant Vogtle Units 3 and 4, with Southern Nuclear serving as project manager and Bechtel serving as the primary construction contractor, as well as a modification of the Vogtle Cost Settlement Agreement. The Georgia PSC's related order stated that under the modified Vogtle Cost Settlement Agreement, (i) none of the $3.3 billion of costs incurred through December 31, 2015 should be disallowed as imprudent; (ii) capital costs incurred up to $5.68 billion would be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs; (iii) Georgia Power would have the burden of proof to show that any capital costs above $5.68 billion were prudent; (iv) Georgia Power's total project capital cost forecast of $7.3 billion (net of $1.7 billion received under the Guarantee Settlement Agreement and $188 million in Customer Refunds recognized as a regulatory liability in 2017) was found reasonable and did not represent a cost cap; and (v) prudence decisions would be made subsequent to achieving fuel load for Unit 4.

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In its order, the Georgia PSC also stated if other conditions change and assumptions upon which Georgia Power's seventeenth VCM report are based do not materialize, the Georgia PSC reserved the right to reconsider the decision to continue construction.
In the second quarter 2018, Georgia Power revised its base cost forecast and estimated contingency to complete construction and start-up of Plant Vogtle Units 3 and 4 to $8.0 billion and $0.4 billion, respectively, for a total project capital cost forecast of $8.4 billion (net of $1.7 billion received under the Guarantee Settlement Agreement and $188 million in Customer Refunds recognized as a regulatory liability in 2017). Although Georgia Power believes these incremental costs are reasonable and necessary to complete the project and the Georgia PSC has stated the $7.3 billion estimate included in the seventeenth VCM proceeding does not represent a cost cap, Georgia Power does not intend to seek rate recovery for the $0.7 billion increase in costs included in the revised base capital cost forecast, which will be filed with the Georgia PSC in the nineteenth VCM report on August 31, 2018. In connection with future VCM filings, Georgia Power may request the Georgia PSC to evaluate costs included in the revised construction contingency estimate for rate recovery as and when they are appropriately included in the base capital cost forecast. After considering the significant level of uncertainty that exists regarding the future recoverability of costs included in the construction contingency estimate since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in these future regulatory proceedings, Georgia Power has recorded a total pre-tax charge to income of $1.1 billion ($0.8 billion after tax) as of June 30, 2018.
Georgia Power's revised cost estimate reflects an expected in-service date of November 2021 for Unit 3 and November 2022 for Unit 4.
As construction continues, challenges with management of contractors, subcontractors, and vendors; labor productivity, availability, and/or cost escalation; procurement, fabrication, delivery, assembly, and/or installation, including any required engineering changes, of plant systems, structures, and components (some of which are based on new technology that is just beginning initial operation in the global nuclear industry at this scale); or other issues could arise and change the projected schedule and estimated cost.
There have been technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4 at the federal and state level and additional challenges may arise. Processes are in place that are designed to assure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating licenses, including inspections by Southern Nuclear and the NRC that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the NRC. Various design and other licensing-based compliance matters, including the timely resolution of Inspections, Tests, Analyses, and Acceptance Criteria and the related approvals by the NRC, may arise, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs.
The ultimate outcome of these matters cannot be determined at this time. Any extension of the in-service dates of November 2021 for Unit 3 and November 2022 for Unit 4 is currently estimated to result in additional base capital costs of approximately $50 million per month, based on Georgia Power's ownership interests, and AFUDC of approximately $12 million per month. While Georgia Power is not precluded from seeking recovery of any future capital cost forecast increase, management will ultimately determine whether or not to seek recovery. Any further changes to the capital cost forecast that are not expected to be recoverable through regulated rates will be required to be charged to income and such charges could be material.
Given the significant complexity involved in estimating the future costs to complete construction and start-up of Plant Vogtle Units 3 and 4 and the significant management judgment necessary to assess the related uncertainties surrounding future rate recovery of any projected cost increases, as well as the potential impact on Southern Company's results of operations and cash flows, Southern Company considers these items to be critical accounting estimates. See Note 3 to the financial statements of Southern Company under "Nuclear Construction" in Item 8 of

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the Form 10-K and Note (B) to the Condensed Financial Statements under "Nuclear Construction" herein for additional information.
Recently Issued Accounting Standards
See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Recently Issued Accounting Standards" of Southern Company in Item 7 of the Form 10-K for additional information regarding ASU No. 2016-02, Leases (Topic 842). See Note (A) to the Condensed Financial Statements herein for information regarding Southern Company's recently adopted accounting standards.
FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY "Overview" of Southern Company in Item 7 of the Form 10-K for additional information. Southern Company's financial condition remained stable at June 30, 2018.March 31, 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 $3.3$0.7 billion for the first sixthree months of 2018, an increase2019, a decrease of $0.5$0.8 billion from the corresponding period in 2017.2018. The increasedecrease in net cash provided from operating activities was primarily due to an increase in fuel cost recovery and an increase in other current liabilities, primarily due to the timing of customer billing reductions related tovendor payments and the Tax Reform Legislation.impacts of the Gulf Power disposition and the Southern Company Gas Dispositions. Net cash used forprovided from investing activities totaled $3.6$2.5 billion for the first sixthree months of 20182019 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 provided fromused for financing activities totaled $0.2$3.4 billion for the first sixthree months of 20182019 primarily due to an increase in commercial paper borrowings and proceeds from Southern Power's salerepayments of a 33% equity interest in a limited partnership indirectly owning substantially all of its solar facilities, partially offset by common stock dividend payments andshort-term bank debt, net redemptions and repurchases of long-term debt, and short-term debt.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 sixthree months of 20182019 include the reclassification of $7.3 billion and $3.5 billiondecreases in total assets and liabilities held for sale of $4.9 billion and $3.2 billion, respectively, associated with Gulf Power, Elizabethtown Gas, Elkton Gas, and Florida City Gas as described in Note (J)primarily related to the Condensed Financial Statements herein under "sale of Gulf Power; the recording of $1.9 billion in operating lease right-of-use assets, net of amortization and operating lease obligations related to the adoption of FASB ASC Topic 842, Assets Held for SaleLeases;" a decrease of $1.7 billion in notes payable related to the repayment of short-term bank debt; an increase of $2.8$1.6 billion in total stockholders' equity primarily related to the gain on the sale

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of Gulf Power; an increase of $1.4 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; a decrease of $1.2 billion in long-term debt (including amounts due within one year) resulting from net repayments of long-term debt; and an increase of $0.8 billion in total property, plant, and equipment primarily related to the traditional electric operating companies' installation of equipment to comply with environmental standards and construction of electric generation, transmission, and distribution facilities, as well as an increase in AROs at Alabama Power, partially offset by the charge related to the construction of Plant Vogtle Units 3 and 4; an increase of $2.5 billion in notes payable primarily related to increased commercial paper borrowings and issuances of short-term bank debt; a decrease of $2.3 billion in long-term debt (including amounts due within one year) resulting from the repayment of long-term debt; an increase of $1.7 billion in noncontrolling interests primarily related to Southern Power's sale of a 33% equity interest in a limited partnership indirectly owning substantially all of its solar facilities; and an increase of $1.5 billion in ARO liabilities primarily related to revised estimates for ash pond closure costs at Alabama Power to comply with the CCR Rule.facilities. See Notes (A)(F), (B), (F)(K), and (J)(L) to the Condensed Financial Statements under "Asset Retirement Obligations," "Nuclear Construction," "Financing Activities," and "Southern Power – Sale of Solar Facility Interests," respectively, herein for additional information.
At the end of the secondfirst quarter 2018,2019, the market price of Southern Company's common stock was $46.31$51.68 per share (based on the closing price as reported on the New York Stock Exchange) and the book value was $23.31$25.41 per share, representing a market-to-book ratio of 199%203%, compared to $48.09, $23.99,$43.92, $23.91, and 201%184%, respectively, at the end of

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2017. 2018. Southern Company's common stock dividend for the secondfirst quarter 20182019 was $0.60 per share compared to $0.58 per share in the secondfirst quarter 2017.2018.
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 $2.2$2.3 billion will be required through June 30, 2019March 31, 2020 to fund maturities of long-term debt. See "Sources of Capital" herein for additional information.
The Southern Company system's construction program is currently estimated to total approximately $8.8 billion for 2018, $8.2 billion for 2019, $7.2 billion for 2020, $7.0 billion for 2021, and $6.7 billion for 2022. These amounts include expenditures of approximately $1.4 billion, $1.4 billion, $0.9 billion, $1.0 billion, and $0.6 billion for the construction of Plant Vogtle Units 3 and 4 in 2018, 2019, 2020, 2021, and 2022, respectively, and an average of approximately $0.5 billion per year for 2018 through 2022 for Southern Power's planned expenditures for plant acquisitions and placeholder growth, as revised subsequent to Tax Reform Legislation. These amounts also include capital expenditures related to contractual purchase commitments for nuclear fuel, capital expenditures covered under LTSAs, and costs, which are immaterial to Southern Company, relating to assets divested during 2018 and held for sale at June 30, 2018. Estimated capital expenditures to comply with environmental laws and regulations included in these amounts are $1.1 billion, $0.3 billion, $0.4 billion, $0.5 billion, and $0.5 billion for 2018, 2019, 2020, 2021, and 2022, respectively. These estimated expenditures do not include any potential compliance costs associated with the regulation of CO2 emissions from fossil fuel-fired electric generating units.
The traditional electric operating companies also anticipate costs associated with closure and monitoring of ash ponds in accordance with the CCR Rule, which are reflected in Southern Company's ARO liabilities. These costs, which are expected to change as the Southern Company system continues to refine its assumptions underlying the cost estimates and evaluate the method and timing of compliance activities, are currently estimated to be approximately $0.3 billion, $0.4 billion, $0.5 billion, $0.6 billion, and $0.5 billion for 2018, 2019, 2020, 2021, and 2022, respectively. For information regarding expected changes to these cost estimates during the second half of 2018, see FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Coal Combustion Residuals" and Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein. Also see Note 1 to the financial statements of Southern Company under "Asset Retirement Obligations and Other Costs of Removal" in Item 8 of the Form 10-K for additional information on AROs.
The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental laws and regulations; the outcome of any legal challenges to environmental rules; changes in electric generating plants, including unit retirements and replacements and adding or changing fuel sources at existing electric generating units, to meet regulatory requirements; changes in FERC rules and regulations; state regulatory agency approvals; changes in the expected environmental compliance program; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. Additionally, planned expenditures for plant acquisitions may vary due to market opportunities and Southern Power's ability to execute its growth strategy. See Note 1215 to the financial statements of Southern Company under "Southern Power" in Item 8 of the Form 10-K and Note (J)(K) to the Condensed Financial Statements under "Southern Power" herein for additional information regarding Southern Power's plant acquisitions.acquisitions and construction projects.
The construction program also includes Plant Vogtle Units 3 and 4, which includes components based on new technology that is just beginningonly 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,productivity; challenges with management of contractors, subcontractors, or vendors; adverse weather conditions; shortages, increased costs, or inconsistent quality of equipment, materials, and labor; contractor or supplier delay; non-performance under construction, operating, or other agreements; operational readiness, including specialized operator training and required site safety programs; engineering or design problems; design and other licensing-based compliance matters, including the timely resolution of ITAAC and the related approvals by the NRC; challenges with start-up activities, including major equipment failure and system integration; 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 PowerNuclear Construction" herein for information regarding Plant Vogtle Units 3 and 4 and additional factors that may impact construction expenditures.

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contractors, subcontractors, or vendors, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, contractor or supplier delay, non-performance under construction, operating, or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities (including major equipment failure and system integration), and/or operational performance. See Note 3 to the financial statements of Southern Company under "Nuclear Construction" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Nuclear Construction" herein for information regarding Plant Vogtle Units 3 and 4 and additional factors that may impact construction expenditures.
Sources of Capital
Southern Company intends to meet its future capital needs through operating cash flows, borrowings from financial institutions, and debt and equity issuances in the capital markets. Southern Company also plans to utilize the proceeds from the disposition of Gulf Power when completed for future capital needs. Equity capital can be provided from any combination of Southern Company's stock plans, private placements, or public offerings. The amount and timing of additional equity and debt issuances in 2018,2019, as well as in subsequent years, will be contingent on Southern Company's investment opportunities and the Southern Company system's capital requirements and will depend upon prevailing market conditions and other factors. See "Capital Requirements and Contractual Obligations" herein for additional information.
Except as described herein, the traditional electric operating companies, Southern Power, and Southern Company Gas plan to obtain the funds required for construction and other purposes from operating cash flows, external security issuances, borrowings from financial institutions, and equity contributions or loans from Southern Company. Southern Power also plans to utilize tax equity partnership contributions. Southern Company Gas also plans to utilize the proceedscontributions, as well as funds resulting from the dispositions of Elizabethtown Gas, Elkton Gas, Florida City Gas, and Pivotal Home Solutions for future capital needs.its pending asset sales. 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 sales of Plants Mankato and Nacogdoches.
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, with the DOE, under which the proceeds of borrowings may be used to reimburse Georgia Power for Eligible Project Costs incurred in connection with its construction of Plant Vogtle Units 3 and 4.
Under the 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 ofthrough the FFB in an amount up to $3.46approximately $5.130 billion, (not toprovided that total aggregate borrowings under the FFB Credit Facilities may not exceed 70% of (i) Eligible Project Costs) to be madeCosts minus (ii) approximately $1.492 billion (reflecting the amounts received by Georgia Power under a multi-advance credit facility (FFB Credit Facility) among Georgia Power, the DOE, andGuarantee Settlement Agreement less the FFB. As of June 30, 2018,Customer Refunds). At March 31, 2019, Georgia Power had borrowed $2.6$3.46 billion under the FFB Credit Facility. In July 2017, Georgia Power entered into an amendment to the Loan Guarantee Agreement, which provides that further advances are conditioned upon the DOE's approval of any agreements entered into in replacement of the Vogtle 3 and 4 Agreement and satisfaction of certain other conditions.Facilities.
In September 2017, the DOE issued a conditional commitment to Georgia Power for up to approximately $1.67 billion of additional guaranteed loans under the Loan Guarantee Agreement. This conditional commitment expires on September 30, 2018, subject to any further extension approved by the DOE. Final approval and issuance of these additional loan guarantees by the DOE cannot be assured and are subject to the negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions, including the Vogtle Owners' votes to continue construction. See Note 6 to the financial statements of Southern Company under "DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements under "DOE Loan Guarantee Borrowings" herein for additional information regarding the Amended and Restated Loan Guarantee Agreement, including applicable covenants, events of default, mandatory prepayment events, (including any decision not to continue construction of Plant Vogtle Units 3 and 4), and additional conditions to borrowing. Also see Note (B) to the Condensed Financial Statements under "Georgia PowerNuclear Construction" herein for additional information regarding Plant Vogtle Units 3 and 4.

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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, 2018,March 31, 2019, Southern Company's current liabilities exceeded current assets by $2.7$1.2 billion, primarily due to notes payable of $5.0 billion (comprised of approximately $3.0 billion at the parent company, $0.5 billion at Georgia Power, $0.1 billion at Gulf Power, $0.1 billion at Mississippi Power, $0.3 billion at Southern Power, and $1.0 billion at Southern Company Gas) and long-term debt that is due within one year of $2.2$2.3 billion (comprised of(including approximately $1.0 billion at the parent company, $0.2 billion at Alabama Power, $0.5 billion at Georgia Power, $0.3 billion at Mississippi Power, $0.6 billion at Southern Power, and $0.2$0.4 billion at Southern Company Gas). and notes payable of $1.3 billion (including approximately $0.5 billion at the parent company, $0.3 billion at Georgia Power, $0.1 billion at Southern Power, and $0.4 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

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operating companies, Southern Power, and Southern Company Gas, equity contributions and/or loans from Southern Company to meet their short-term capital needs.
At June 30, 2018,March 31, 2019, Southern Company and its subsidiaries had approximately $2.0$1.4 billion of cash and cash equivalents. Committed credit arrangements with banks at June 30, 2018March 31, 2019 were as follows:
Expires   
Executable Term
Loans
 
Expires Within
One Year
Expires  
Company2018201920202022 Total Unused 
One
Year
 
Term
Out
 
No Term
Out
201920202022 Total 
Unused(d)
(in millions)(in millions)
Southern Company(a)
$
$
$
$2,000
 $2,000
 $1,999
 $
 $
 $
$
$
$2,000
 $2,000
 $1,999
Alabama Power2
31
500
800
 1,333
 1,333
 
 
 33
33
500
800
 1,333
 1,333
Georgia Power


1,750
 1,750
 1,736
 
 
 


1,750
 1,750
 1,736
Gulf Power20
25
235

 280
 280
 45
 45
 
Mississippi Power100



 100
 100
 
 
 100
100


 100
 100
Southern Power Company(b)



750
 750
 728
 
 
 
Southern Power(b)


750
 750
 741
Southern Company Gas(c)



1,900
 1,900
 1,895
 
 
 


1,900
 1,900
 1,895
Other
30


 30
 30
 
 
 30
30


 30
 30
Southern Company Consolidated$122
$86
$735
$7,200
 $8,143
 $8,101
 $45
 $45
 $163
$163
$500
$7,200
 $7,863
 $7,834
(a)Represents the Southern Company parent entity.
(b)
Does not include Southern Power'sPower Company's $120 million continuing letter of credit facility for standby letters of credit expiring in 2019,2021, of which $2324 million remainswas unused at June 30, 2018March 31, 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 $1.4 billion of these arrangements.this arrangement. Southern Company Gas' committed credit arrangementsarrangement also includeincludes $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.
(d)Amounts used are for letters of credit.
See Note 68 to the financial statements of Southern Company under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
Most of these bank credit arrangements, as well as the term loan arrangements of Southern Company, Alabama Power, Mississippi Power, and Southern Power Company, 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, 2018,March 31, 2019, Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Gas, Nicor Gas, and Nicor GasSEGCO were in compliance with all such covenants. All but $40 millionNone of the bank credit arrangements do not contain material adverse change clauses at the time of borrowings.
Subject to applicable market conditions, Southern Company and its subsidiaries expect to renew or replace their bank credit arrangements as needed, prior to expiration. In connection therewith, Southern Company and its subsidiaries may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
A portion of the unused credit with banks is allocated to provide liquidity support to the revenue bonds of the traditional electric operating companies and the commercial paper programs of Southern Company, the traditional electric operating companies, Southern Power Company, Southern Company Gas, Nicor Gas, and Nicor Gas.SEGCO. The amount of variable rate revenue bonds of the traditional electric operating companies outstanding requiring liquidity support as of June 30, 2018March 31, 2019 was approximately $1.5$1.4 billion. In addition, at June 30, 2018,March 31, 2019, the traditional electric operating companies had approximately $482$432 million of revenue bonds outstanding that wereare required to be remarketed within the next 12 months. Subsequent to June 30, 2018,March 31, 2019, Georgia Power purchased and held approximately $43$115 million of theseoutstanding pollution control revenue bonds required to be remarketed.

39

Table of Mississippi Power were purchased and held by Mississippi Power.Contents
SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Southern Company, the traditional electric operating companies (other than Mississippi Power),Alabama Power, Georgia Power, Southern Power Company, Southern Company Gas, and 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.
Details of short-term borrowings were as follows:
 
Short-term Debt at
June 30, 2018
 
Short-term Debt During the Period(*)
 
Short-term Debt at
March 31, 2019
 
Short-term Debt During the Period(*)
 
Amount
Outstanding
 
Weighted
Average
Interest
Rate
 
Average
Amount
Outstanding
 
Weighted
Average
Interest
Rate
 
Maximum
Amount
Outstanding
 
Amount
Outstanding
 
Weighted
Average
Interest
Rate
 
Average
Amount
Outstanding
 
Weighted
Average
Interest
Rate
 
Maximum
Amount
Outstanding
 (in millions)   (in millions)   (in millions) (in millions)   (in millions)   (in millions)
Commercial paper $3,002
 2.5% $2,292
 2.4% $3,042
 $1,151
 2.9% $1,248
 2.9% $2,293
Short-term bank debt 1,979
 3.0% 1,987
 2.8% 2,254
 100
 3.1% 208
 3.2% 1,850
Total $4,981
 2.7% $4,279
 2.6%   $1,251
 2.9% $1,456
 2.9%  
(*)Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 2018.March 31, 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, 2018,March 31, 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.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The maximum potential collateral requirements under these contracts at June 30, 2018March 31, 2019 were as follows:
Credit RatingsMaximum Potential
Collateral
Requirements
Maximum Potential
Collateral
Requirements
(in millions)(in millions)
At BBB and/or Baa2$38
$30
At BBB- and/or Baa3$576
$433
At BB+ and/or Ba1(*)
$2,141
$1,988
(*)Any additional credit rating downgrades at or below BB- and/or Ba3 could increase collateral requirements up to an additional $38 million.
Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of Southern Company and its subsidiaries to access capital markets, and would be likely to impact the cost at which they do so.
On February 26, 2018, Moody's revised its rating outlook for Mississippi Power from stable to positive.
On February 28, 2018, Fitch downgraded the senior unsecured long-term debt rating of Southern Company to BBB+ from A- with a stable outlook and of Georgia Power to A from A+ with a negative outlook.
On March 14, 2018, S&P upgraded the senior unsecured long-term debt rating of Mississippi Power to A- from BBB+. The outlook remained negative.
On May 21, 2018, S&P revised its rating outlook for Gulf Power from negative to stable.
As a result of the Tax Reform Legislation, certain financial metrics, such as the funds from operations to debt percentage, used by the credit rating agencies to assess Southern Company and its subsidiaries may be negatively impacted. Southern Company and certainmost of its regulated subsidiaries are takinghave 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 32 to the financial statements of Southern Company in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements herein for additional information related to state PSC or other regulatory agency actions related to the Tax Reform Legislation, including recent approvals of capital structure adjustments for Alabama Power, Georgia Power, Gulf Power, and Atlanta Gas Light by their respective state PSCs, which are expected to help mitigate the potential adverse impacts to certain of their credit metrics.
Financing Activities
During the first six months of 2018, Southern Company issued approximately 6.6 million shares of common stock primarily through employee equity compensation plans and received proceeds of approximately $222 million.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

additional information related to state PSC or other regulatory agency actions related to the Tax Reform Legislation, including approvals of capital structure adjustments for Alabama Power, Georgia Power, and Atlanta Gas Light by their respective state PSCs and a similar request by Nicor Gas currently pending Illinois Commission approval, which are expected to help mitigate the potential adverse impacts to certain of their credit metrics.
Financing Activities
During the first three months of 2019, Southern Company issued approximately 6.5 million shares of common stock primarily through employee equity compensation plans and received proceeds of approximately $224 million.
The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first sixthree months of 2018:2019:
Company
Senior
Note
Issuances
 Senior Note Maturities, Redemptions, and Repurchases 
Revenue Bond
Maturities, Redemptions, and
Repurchases
 
Other Long-Term
Debt Redemptions
and Maturities(*)
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)(in millions)
Southern Company(b)
$2,100
 $
 $
 $
 $
Alabama Power$500
 $
 $
 $
200
 
 
 
 
Georgia Power
 1,000
 398
 104

 343
 108
 835
 2
Mississippi Power600
 
 
 900

 43
 
 
 
Southern Power
 350
 
 420
Southern Company Gas
 
 200
 
Other
 
 
 7

 
 
 
 19
Southern Company Consolidated$1,100
 $1,350
 $598
 $1,431
$2,300
 $386
 $108
 $835
 $21
(*)(a)Includes reductions in capitalfinance lease obligations resulting from cash payments under capitalfinance 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, andcapital. The subsidiaries also used the proceeds for the subsidiaries, their construction programs.
In March 2018,January 2019, Southern Company entered intorepaid a $900 million short-term floating rate bank loan bearing interest based on one-month LIBOR.
In April 2018, Southern Company borrowed $250 million pursuant to a short-term uncommitted bank credit arrangement which bears interest atand a rate agreed upon by Southern Company and the bank from time to time and is payable on no less than 30 days' demand by the bank.
In June 2018, Southern Company repaid at maturity two $100 million$1.5 billion short-term floating rate bank term loans.loan.
InAlso in January 2018, Georgia Power repaid its outstanding $150 million short-term floating rate bank loan due May 31, 2018.
In May 2018,2019, through cash tender offers, Georgia PowerSouthern Company repurchased and retired $89approximately $522 million of the $250$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 2007A 5.65%2014B 2.15% Senior Notes due MarchSeptember 1, 2037, $3262019 (Series 2014B Notes), and approximately $504 million of the $500$750 million aggregate principal amount outstanding of its Series 2009A 5.95% Senior2018A Floating Rate Notes due February 1, 2039, and $335 million of the $600 million aggregate principal amount outstanding of its Series 2010B 5.40% Senior Notes due June 1, 2040,14, 2020 (Series 2018A Notes), for an aggregate purchase price, excluding accrued and unpaid interest, of $902 million.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.
In March 2018, Mississippi Power entered into a $300 million short-term floating rate bank loan bearing interest based on one-month LIBOR, of which $200 million was repaidAs reflected in the second quarter 2018 and $50 million was repaid on July 31, 2018. The proceeds of this loan, together withtable above, in March 2019, Georgia Power made additional borrowings under the proceeds of Mississippi Power's $600 million senior notes issuances, were used to repay Mississippi Power's $900 million unsecured floating rate term loan.
Subsequent to June 30, 2018, approximately $43 millionFFB Credit Facilities in pollution control revenue bonds of Mississippi Power were purchased and held by Mississippi Power. These bonds may be remarketed to the public in the future.
In May 2018, Southern Power entered into two short-term floating rate bank loans, each for an aggregate principal amount of $100$835 million which bearat an interest based on one-month LIBOR.
Inrate of 3.213% through the second quarter 2018, Pivotal Utility Holdings caused $200 million aggregate principal amountfinal maturity date of gas facility revenue bondsFebruary 20, 2044. The proceeds were used to be redeemed. Also inreimburse Georgia Power for Eligible Project Costs relating to the second quarter 2018, Pivotal Utility Holdings, as borrower,construction of Plant Vogtle Units 3 and Southern Company Gas, as guarantor, entered into a $181 million short-term delayed draw floating rate bank term loan4.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

bearing interest based on one-month LIBOR, which Pivotal Utility Holdings used to repay the gas facility revenue bonds. Subsequent to June 30, 2018, Pivotal Utility Holdings repaid this short-term loan.
In May 2018, Southern Company Gas Capital borrowed $95 million pursuantMarch 31, 2019, Georgia Power purchased and held the following pollution control revenue bonds, which may be reoffered to a short-term uncommitted bank credit arrangement, guaranteed by Southern Company Gas, bearing interestthe public at a rate agreed upon by Southern Company Gas Capital and the bank from time to time and payable on no less than 30 days' demand by the bank. The proceeds of the loan were used to pay down short-term debt. Subsequent to June 30, 2018, Southern Company Gas Capital repaid this loan.later date:
Subsequent to June 30, 2018, Nicor Gas agreed to issue $300$55 million aggregate principal amount of first mortgage bonds in a private placement, $100Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Fourth Series 1994;
$30 million aggregate principal amount of which is expected to be issued in August 2018Development 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 $200
$10 million aggregate principal amount of which is expected to be issued in November 2018.Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), Second Series 1994.
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Southern Company and its subsidiaries plan to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.

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PART I
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
During the three months ended June 30, 2018,March 31, 2019, there were no material changes to Southern Company's, Alabama Power's, Georgia Power's, Gulf Power's, Mississippi Power's, and Southern Power's disclosures about market risk. For additional market risk disclosures relating to Southern Company Gas, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of Southern Company Gas herein. For an in-depth discussion of each registrant's market risks, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of each registrant in Item 7 of the Form 10-K and Note 1 to the financial statements of each registrant under "Financial Instruments," Note 11Instruments" and Notes 13 and 14 to the financial statements of Southern Company, Alabama Power, and Georgia Power, Note 10 to the financial statements of Gulf Power, Mississippi Power, and Southern Company Gas, and Note 9 to the financial statements of Southern Power in Item 8 of the Form 10-K. Also see Note (D)Notes (I) and Note (I)(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, Gulf Power, Mississippi Power, Southern Power, and Southern Company Gas conducted separate evaluations under the supervision and with the participation of each company's management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of the disclosure controls and procedures (as defined in Sections 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended). Based upon these evaluations, the Chief Executive Officer and the Chief Financial Officer, in each case, concluded that the disclosure controls and procedures are effective.
(b)Changes in internal controls over financial reporting.
There have been no changes in Southern Company's, Alabama Power's, Georgia Power's, Gulf Power's, Mississippi Power's, Southern Power's, or Southern Company Gas' internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended) during the secondfirst quarter 20182019 that have materially affected or are reasonably likely to materially affect Southern Company's, Alabama Power's, Georgia Power's, Gulf Power's, Mississippi Power's, Southern Power's, or Southern Company Gas' internal control over financial reporting.

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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,
For the Three Months
Ended March 31,
2018 2017 2018 20172019 2018
(in millions) (in millions)(in millions)
Operating Revenues:          
Retail revenues$1,338
 $1,333
 $2,624
 $2,560
$1,213
 $1,285
Wholesale revenues, non-affiliates65
 68
 139
 133
61
 74
Wholesale revenues, affiliates31
 32
 82
 65
60
 51
Other revenues69
 51
 131
 108
74
 63
Total operating revenues1,503
 1,484
 2,976
 2,866
1,408
 1,473
Operating Expenses:          
Fuel347
 303
 672
 601
301
 326
Purchased power, non-affiliates48
 40
 113
 75
37
 64
Purchased power, affiliates43
 34
 80
 62
21
 37
Other operations and maintenance402
 389
 788
 772
409
 387
Depreciation and amortization189
 183
 379
 364
199
 189
Taxes other than income taxes94
 95
 192
 191
103
 98
Total operating expenses1,123
 1,044
 2,224
 2,065
1,070
 1,101
Operating Income380
 440
 752
 801
338
 372
Other Income and (Expense):          
Allowance for equity funds used during construction14
 8
 27
 16
14
 13
Interest expense, net of amounts capitalized(80) (77) (158) (153)(83) (79)
Other income (expense), net12
 15
 15
 25
14
 5
Total other income and (expense)(54) (54) (116) (112)(55) (61)
Earnings Before Income Taxes326
 386
 636
 689
283
 311
Income taxes64
 151
 145
 277
62
 82
Net Income262
 235
 491
 412
221
 229
Dividends on Preferred and Preference Stock3
 5
 7
 9
Net Income After Dividends on Preferred and Preference Stock$259
 $230
 $484
 $403
Dividends on Preferred Stock4
 4
Net Income After Dividends on Preferred Stock$217
 $225

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
 
For the Three Months
Ended June 30,
 For the Six Months
Ended June 30,
For the Three Months
Ended March 31,
2018 2017 2018 20172019 2018
(in millions) (in millions)(in millions)
Net Income$262
 $235
 $491
 $412
$221
 $229
Other comprehensive income (loss):          
Qualifying hedges:          
Reclassification adjustment for amounts included in net income,
net of tax of $-, $1, $1, and $1, respectively
1
 1
 2
 2
Reclassification adjustment for amounts included in net income,
net of tax of $- and $1, respectively
1
 1
Total other comprehensive income (loss)1
 1
 2
 2
1
 1
Comprehensive Income$263
 $236
 $493
 $414
$222
 $230
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,
For the Three Months
Ended March 31,
2018 20172019 2018
(in millions)(in millions)
Operating Activities:      
Net income$491
 $412
$221
 $229
Adjustments to reconcile net income to net cash provided from operating activities —      
Depreciation and amortization, total452
 442
244
 228
Deferred income taxes48
 192

 32
Allowance for equity funds used during construction(27) (16)
Pension, postretirement, and other employee benefits(28) (24)
Other, net(40) 20
(24) (21)
Changes in certain current assets and liabilities —      
-Receivables(153) (58)105
 (1)
-Prepayments(57) (56)(78) (82)
-Materials and supplies(47) (18)(4) (27)
-Other current assets29
 12
19
 19
-Accounts payable(196) (154)(286) (216)
-Accrued taxes134
 52
80
 57
-Accrued compensation(70) (74)(122) (108)
-Retail fuel cost over recovery
 (65)
-Other current liabilities116
 7
(9) 45
Net cash provided from operating activities652
 672
146
 155
Investing Activities:      
Property additions(997) (738)(390) (490)
Nuclear decommissioning trust fund purchases(131) (117)(68) (50)
Nuclear decommissioning trust fund sales131
 117
68
 51
Cost of removal, net of salvage(34) (54)(16) (19)
Change in construction payables(29) 48
(95) (50)
Other investing activities(15) (15)(10) (6)
Net cash used for investing activities(1,075) (759)(511) (564)
Financing Activities:      
Proceeds —   
Senior notes500
 550
Capital contributions from parent company488
 327
Increase in notes payable, net
 245
Proceeds — Capital contributions from parent company1,232
 484
Redemptions — Senior notes
 (200)(200) 
Payment of common stock dividends(402) (357)(211) (202)
Other financing activities(21) (14)(10) (9)
Net cash provided from financing activities565
 306
811
 518
Net Change in Cash, Cash Equivalents, and Restricted Cash142
 219
446
 109
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period544
 420
313
 544
Cash, Cash Equivalents, and Restricted Cash at End of Period$686
 $639
$759
 $653
Supplemental Cash Flow Information:      
Cash paid during the period for —      
Interest (net of $10 and $6 capitalized for 2018 and 2017, respectively)$143
 $140
Interest (net of $5 and $5 capitalized for 2019 and 2018, respectively)$89
 $84
Income taxes, net17
 88

 9
Noncash transactions — Accrued property additions at end of period216
 132
176
 195
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, 2018 At December 31, 2017 At March 31, 2019 At December 31, 2018
 (in millions) (in millions)
Current Assets:        
Cash and cash equivalents $686
 $544
 $759
 $313
Receivables —        
Customer accounts receivable 401
 355
 382
 403
Unbilled revenues 174
 162
 126
 150
Under recovered regulatory clause revenues 28
 
Affiliated 54
 43
 45
 94
Other accounts and notes receivable 41
 55
 58
 51
Accumulated provision for uncollectible accounts (10) (9) (10) (10)
Fossil fuel stock 154
 184
 120
 141
Materials and supplies 518
 458
 558
 546
Prepaid expenses 90
 85
 113
 66
Other regulatory assets, current 146
 124
Other regulatory assets 125
 137
Other current assets 11
 5
 21
 18
Total current assets 2,293
 2,006
 2,297
 1,909
Property, Plant, and Equipment:        
In service 29,374
 27,326
 28,810
 30,402
Less: Accumulated provision for depreciation 9,813
 9,563
 9,447
 9,988
Plant in service, net of depreciation 19,561
 17,763
 19,363
 20,414
Other utility plant, net 1,315
 
Nuclear fuel, at amortized cost 337
 339
 320
 324
Construction work in progress 1,172
 908
 1,023
 1,113
Total property, plant, and equipment 21,070
 19,010
 22,021
 21,851
Other Property and Investments:        
Equity investments in unconsolidated subsidiaries 66
 67
 64
 65
Nuclear decommissioning trusts, at fair value 906
 903
 933
 847
Miscellaneous property and investments 124
 124
 129
 127
Total other property and investments 1,096
 1,094
 1,126
 1,039
Deferred Charges and Other Assets:        
Operating lease right-of-use assets, net of amortization 160
 
Deferred charges related to income taxes 234
 239
 239
 240
Deferred under recovered regulatory clause revenues 121
 54
 21
 116
Other regulatory assets, deferred 1,244
 1,272
 1,350
 1,386
Other deferred charges and assets 212
 189
 193
 189
Total deferred charges and other assets 1,811
 1,754
 1,963
 1,931
Total Assets $26,270
 $23,864
 $27,407
 $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, 2018 At December 31, 2017 At March 31, 2019 At December 31, 2018
 (in millions) (in millions)
Current Liabilities:        
Securities due within one year $200
 $
 $1
 $201
Accounts payable —        
Affiliated 298
 327
 262
 364
Other 398
 585
 346
 614
Customer deposits 95
 92
 97
 96
Accrued taxes 137
 54
 97
 44
Accrued interest 81
 77
 77
 89
Accrued compensation 140
 205
 102
 227
Other regulatory liabilities, current 118
 1
Asset retirement obligations 163
 163
Other current liabilities 143
 59
 97
 161
Total current liabilities 1,610
 1,400
 1,242
 1,959
Long-term Debt 7,922
 7,628
 7,924
 7,923
Deferred Credits and Other Liabilities:        
Accumulated deferred income taxes 2,829
 2,760
 2,971
 2,962
Deferred credits related to income taxes 2,061
 2,082
 2,015
 2,027
Accumulated deferred ITCs 109
 112
 105
 106
Employee benefit obligations 275
 304
 302
 314
Asset retirement obligations 3,085
 1,702
Operating lease obligations 147
 
Asset retirement obligations, deferred 3,064
 3,047
Other cost of removal obligations 580
 609
 489
 497
Other regulatory liabilities, deferred 43
 84
Other regulatory liabilities 107
 69
Other deferred credits and liabilities 64
 63
 30
 58
Total deferred credits and other liabilities 9,046
 7,716
 9,230
 9,080
Total Liabilities 18,578
 16,744
 18,396
 18,962
Redeemable Preferred Stock 291
 291
 291
 291
Common Stockholder's Equity:    
Common stock, par value $40 per share —    
Authorized — 40,000,000 shares    
Outstanding — 30,537,500 shares 1,222
 1,222
Paid-in capital 3,480
 2,986
Retained earnings 2,729
 2,647
Accumulated other comprehensive loss (30) (26)
Total common stockholder's equity 7,401
 6,829
Common Stockholder's Equity (See accompanying statements)
 8,720
 7,477
Total Liabilities and Stockholder's Equity $26,270
 $23,864
 $27,407
 $26,730
The accompanying notes as they relate to Alabama 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, 201731
 $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, 201831
 $1,222
 $3,474
 $2,670
 $(31) $7,335
            
Balance at December 31, 201831
 $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, 201931
 $1,222
 $4,744
 $2,781
 $(27) $8,720
The accompanying notes as they relate to Alabama Power are an integral part of these condensed financial statements.


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SECONDFIRST QUARTER 20182019 vs. SECONDFIRST QUARTER 2017
AND
YEAR-TO-DATE 2018 vs. YEAR-TO-DATE 2017


OVERVIEW
Alabama Power operates as a vertically integrated utility providing electric service to retail and wholesale customers within its traditional service territory located in the State of Alabama in addition to wholesale customers in the Southeast.
Many factors affect the opportunities, challenges, and risks of Alabama Power's business of providing electric service. These factors include the ability to maintain a constructive regulatory environment, to maintain and grow energy sales and customers, and to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand growth, stringent environmental standards, 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. On May 1, 2018, the Alabama PSC approved modifications to Rate RSE and other commitments designed to position Alabama Power to address the retail rate impact and the growing pressure on its credit quality resulting from the Tax Reform Legislation. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters" and FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" herein for additional information and Note 3 to the financial statements of Alabama Power under "Retail Regulatory Matters – Rate RSE" in Item 8 of the Form 10-K for additional information on Alabama Power's established retail tariff.
Alabama Power continues to focus on several key performance indicators including, but not limited to, customer satisfaction, plant availability, system reliability, and net income after dividends on preferred stock.
RESULTS OF OPERATIONS
Net Income
Second Quarter 2018 vs. Second Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)
(% change)
(change in millions)
(% change)
$29 12.6 $81 20.1
First Quarter 2019 vs. First Quarter 2018
(change in millions)
(% change)
$(8) (3.6)
Alabama Power's net income after dividends on preferred and preference stock for the secondfirst quarter 20182019 was $259$217 million compared to $230$225 million for the corresponding period in 2017. The increase2018. This decrease was primarily related to a decrease in retail revenues associated with milder weather and lower customer usage and an increase in non-fuel operations and maintenance expenses. These decreases to income were partially offset by an increase in retail revenues under Rate CNP Compliance associated with warmer weather experiencedincreases in Alabama Power's service territory in the second quarter 2018 compared to the corresponding period in 2017average net investments and a decrease in income tax expense partially offset by revenues deferred as a regulatory liability for reductions to customer billings, which began in July 2018, related to the Tax Reform Legislation.
Alabama Power's net income after dividends on preferred and preference stock for year-to-date 2018 was $484 million compared to $403 million for the corresponding period in 2017. The increase was primarily related to an increase in retail revenues associated with colder weather experiencedthe application in 2018 of the first quarter 2018 and warmer weather experiencedaccounting order approved by the Alabama PSC in the second quarter 2018 in Alabama Power's service territory compared to the corresponding periods in 2017 and a decrease in income tax expense, partially offset by revenues deferred as a regulatory liability for reductions to customer billings, which began in JulyMay 2018 related to the Tax Reform Legislation and an increase in depreciation.(Tax Reform Accounting Order). See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters" herein and Note 32 to the financial statements of Alabamaunder "Alabama Power under "Retail Regulatory Matters Rate RSE"Tax Reform Accounting Order" in Item 8 of the Form 10-K for additional information.

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Retail Revenues
Second Quarter 2018 vs. Second Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$5 0.4 $64 2.5
First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change)
$(72) (5.6)
In the secondfirst quarter 2018,2019, retail revenues were $1.34$1.21 billion compared to $1.33$1.29 billion for the corresponding period in 2017. For year-to-date 2018, retail revenues were $2.62 billion compared to $2.56 billion for the corresponding period in 2017.2018.

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Details of the changes in retail revenues were as follows:
Second Quarter 2018
Year-to-Date 2018First Quarter 2019
(in millions)
(% change)
(in millions)
(% change)(in millions)
(% change)
Retail – prior year$1,333
   $2,560
  $1,285
  
Estimated change resulting from –          
Rates and pricing(57) (4.2) (108) (4.2)34
 2.6
Sales decline(7) (0.6) (5) (0.2)(17) (1.3)
Weather28
 2.1
 92
 3.6
(25) (1.9)
Fuel and other cost recovery41
 3.1
 85
 3.3
(64) (5.0)
Retail – current year$1,338
 0.4% $2,624
 2.5%$1,213
 (5.6)%
Revenues associated with changes in rates and pricing decreasedincreased in the secondfirst quarter and year-to-date 20182019 when compared to the corresponding periodsperiod in 20172018 primarily due to increased revenues deferred as a regulatory liability for reductions to customer billings, which beganunder Rate CNP Compliance associated with increases in July 2018, related to the Tax Reform Legislation.average net investments. See Note (B) to the Condensed Financial Statements under "Regulatory MattersAlabama Power" herein and Note 32 to the financial statements of Alabama Power under "Retail Regulatory Matters""Alabama Power" in Item 8 of the Form 10-K for additional information.
Revenues attributable to changes in sales decreased in the secondfirst quarter and year-to-date 20182019 when compared to the corresponding periodsperiod in 2017.2018. Weather-adjusted commercial KWH sales decreased 2.3% and 1.6% for3.5% in the secondfirst quarter and year-to-date 2018, respectively,2019 and weather-adjusted residential KWH sales decreased 0.9% and 0.7% for2.3% in the secondfirst quarter and year-to-date 2018, respectively,2019 when compared to the corresponding periodsperiod in 20172018 primarily due to lower customer usage relatedresulting from customer initiatives in energy savings for commercial customers and lower usage due to energy efficiency.more energy-efficient residential appliances. Industrial KWH sales increased 1.6% anddecreased 3.0% forin the secondfirst quarter and year-to-date 2018, respectively,2019 when compared to the corresponding periodsperiod in 20172018 as a result of an increasea decrease in demand resulting from changes in production levels primarily in the pipelinesprimary metals, chemicals, and primary metalspaper sectors, partially offset by a decrease inincreased demand in the paperpipeline sector.
Revenues resulting from changes in weather increased in the second quarter and year-to-date 2018 due to colder weather experienceddecreased in the first quarter 2018 and warmer weather experienced in2019 due to milder weather. In the secondfirst quarter 2018 in Alabama Power's service territory compared to the corresponding periods in 2017. For the second quarter 2018,2019, the resulting increasesdecreases were 3.9%3.3% and 1.7% for residential and commercial sales revenues, respectively. For year-to-date 2018, the resulting increases were 7.0% and 2.4% for residential and commercial sales revenues, respectively.
Fuel and other cost recovery revenues increaseddecreased in the secondfirst quarter and year-to-date 20182019 when compared to the corresponding periodsperiod in 20172018 primarily due to increasesa decrease in KWH generation and the average cost of fuel.generation.
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 32 to the financial statements of Alabama Power under "Retail Regulatory Matters""Alabama Power" in Item 8 of the Form 10-K for additional information.
Wholesale Revenues Non-Affiliates
First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change)
$(13) (17.6)
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.

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In the first quarter 2019, wholesale revenues from sales to non-affiliates were $61 million compared to $74 million for the corresponding period in 2018. The decrease was primarily due to a 10.1% decrease in the price of energy due to lower natural gas prices and a 9.4% decrease in KWH sales as a result of lower demand in the first quarter 2019 compared to the corresponding period in 2018.
Wholesale Revenues Affiliates
Second Quarter 2018 vs. Second Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(1) (3.1) $17 26.2
First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change)
$9 17.6
Wholesale revenues from sales to affiliated companies will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost and energy purchases are generally offset by energy revenues through Alabama Power's energy cost recovery clause.
For year-to-date 2018,In the first quarter 2019, wholesale revenues from sales to affiliates were $82 million compared to $65 million for the corresponding period in 2017. The increase was primarily due to an 12.4% increase in the price of energy and an 11.3% increase in KWH sales as a result of increased demand due to colder weather in the first quarter 2018 compared to the corresponding period in 2017.
Other Revenues
Second Quarter 2018 vs. Second Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$18 35.3 $23 21.3
In the second quarter 2018, other revenues were $69$60 million compared to $51 million for the corresponding period in 2017. For year-to-date 2018,2018. The increase was primarily due to a 33.4% increase in KWH sales partially offset by a 12.6% decrease in the price of energy due to increased hydro generation in the first quarter 2019 as compared to the corresponding period in 2018.
Other Revenues
First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change)
$11 17.5
In the first quarter 2019, other revenues were $131$74 million compared to $108$63 million for the corresponding period in 2017. These increases were2018. This increase was primarily due to an increase in OATT revenues related to unregulatedand opportunity sales of products and services that were reclassified as other revenues as a result of the adoption of ASC 606, Revenue from Contracts with Customers (ASC 606). In prior periods, these revenues were included in other income (expense), net. See Note (A) to the Condensed Financial Statements herein for additional information regarding Alabama Power's adoption of ASC 606. The year-to-date 2018 increase was partially offset by decreases in open access transmission tariff revenues and miscellaneous rents.natural gas.
Fuel and Purchased Power Expenses
Second Quarter 2018
vs.
Second Quarter 2017
 Year-to-Date 2018 vs. Year-to-Date 2017First Quarter 2019 vs. First Quarter 2018
(change in millions)
(% change) (change in millions) (% change)(change in millions) (% change)
Fuel$44
 14.5 $71
 11.8$(25) (7.7)
Purchased power – non-affiliates8
 20.0 38
 50.7(27) (42.2)
Purchased power – affiliates9
 26.5 18
 29.0(16) (43.2)
Total fuel and purchased power expenses$61
 $127
 $(68)  
In the secondfirst quarter 2018,2019, fuel and purchased power expenses were $438$359 million compared to $377$427 million for the corresponding period in 2017.2018. The increasedecrease was primarily due to a $39$53 million increasedecrease related to the volume of KWHs generated (excluding hydro) and purchased and a $7 million increase related to the average cost of fuel, partially offset by a $14 million decrease in the average cost of purchased power.
For year-to-date 2018, fuel and purchased power expenses were $865 million compared to $738 million for the corresponding period in 2017. The increase was primarily due to a $75 million increase related to the volume of KWHs generated and purchased, a $16 million increase related to the average cost of fuel, and a $7 million increase in the average cost of purchased power.

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In addition, fuel expense increased $30 million in both the second quarter and year-to-date 2018 in accordance with an Alabama PSC accounting order authorizing the use of excess deferred income taxes to offset under recovered fuel costs. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory MattersAccounting Order" herein for additional information.
Fuel and purchased power energy transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through Alabama Power's energy cost recovery clause. See Note 32 to the financial statements of Alabamaunder "Alabama Power under "Retail Regulatory Matters – Rate ECR" in Item 8 of the Form 10-K for additional information.

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Details of Alabama Power's generation and purchased power were as follows:
Second Quarter 2018 Second Quarter 2017 Year-to-Date 2018
Year-to-Date 2017First Quarter 2019
First Quarter 2018
Total generation (in billions of KWHs)
15 15 31 3016 16
Total purchased power (in billions of KWHs)
2 1 3 21 1
Sources of generation (percent)
  
Coal53 47 52 4843 50
Nuclear20 25 21 2623 23
Gas20 20 19 2019 18
Hydro7 8 8 615 9
Cost of fuel, generated (in cents per net KWH)(a)
 
Cost of fuel, generated (in cents per net KWH)
 
Coal2.79 2.63 2.74 2.612.78 2.69
Nuclear0.80 0.76 0.77 0.750.78 0.75
Gas2.51 2.75 2.69 2.762.57 2.87
Average cost of fuel, generated (in cents per net KWH)(b)(a)
2.31 2.14 2.27 2.132.19 2.23
Average cost of purchased power (in cents per net KWH)(c)(b)
4.72 5.43 5.72 5.505.75 7.10
(a)Cost of fuel and average cost of fuel, generated excludes a $30 million adjustment associated with the Alabama PSC accounting order related to excess deferred income taxes.
(b)KWHs generated by hydro are excluded from the average cost of fuel, generated.
(c)(b)Average cost of purchased power includes fuel, energy, and transmission purchased by Alabama Power for tolling agreements where power is generated by the provider.
Fuel
In the secondfirst quarter 2018,2019, fuel expense was $347$301 million compared to $303$326 million for the corresponding period in 2017.2018. The increasedecrease was primarily due to a 24.9%79.7% increase in the volume of KWHs generated by hydro, a 12.7% decrease in the volume of KWHs generated by nuclear facilities, a 12.4% decrease in the volume of KWHs generated by hydro facilities, an 8.7% increase in the volume of KWHs generated by coal, a 6.1% increase in the average cost of coal per KWH generated, and a 5.3% increase in the average cost of nuclear per KWH generated. These increases were partially offset by an 8.7%10.5% decrease in the average cost of natural gas per KWH generated, which excludes fuel associated with tolling agreements.
For year-to-date 2018, fuel expense The decrease was $672 million compared to $601 million for the corresponding period in 2017. The increase was primarily due topartially offset by a 14.2% decrease in the volume of KWHs generated by nuclear facilities, a 9.8%4.6% increase in the volume of KWHs generated by coal,natural gas and a 5.0%3.4% increase in the average cost of coal per KWH generated. These increases were partially offset by a 22.6% increase in the volume of KWHs generated by hydro facilities.
In addition, fuel expense increased $30 million in both the second quarter and year-to-date 2018 in accordance with an Alabama PSC accounting order authorizing the use of excess deferred income taxes to offset under recovered

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fuel costs. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory MattersAccounting Order" herein for additional information.
Purchased Power – Non-Affiliates
In the secondfirst quarter 2018,2019, purchased power expense from non-affiliates was $48$37 million compared to $40$64 million for the corresponding period in 2017.2018. The increasedecrease was primarily related to a 24.6% increase in the amount of energy purchased due to warmer weather in the second quarter 2018 compared to the corresponding period in 2017. This increase was partially offset by a 4.4%28.3% decrease in the average cost of purchased power per KWH due to lower natural gas prices.
For year-to-date 2018, purchased power expense from non-affiliates was $113 million compared to $75 million for the corresponding period in 2017. The increase was primarily related toprices and a 29.6% increase19.7% decrease in the amount of energy purchased and a 15.6% increase in the average cost of purchased power per KWH due to coldermilder weather in the first quarter 20182019 compared to the corresponding period in 2017.2018.
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 secondfirst quarter 2018,2019, purchased power expense from affiliates was $43$21 million compared to $34$37 million for the corresponding period in 2017.2018. The increasedecrease was primarily related to a 60.8% increase48.6% decrease in the amount of energy purchased due to warmer weather in the second quarter 2018 compared to the corresponding period in 2017,increased hydro generation, partially offset by a 20.9% decreasean 11.4% increase in the average cost of purchased power per KWH due to lower natural gas prices in the second quarter 2018 compared to the corresponding period in 2017.
For year-to-date 2018, purchased power expense from affiliates was $80 million compared to $62 million for the corresponding period in 2017. The increase was primarily related to a 44% increase in the amount of energy purchased as a result of colder weather in the first quarter 2018 compared to the corresponding period in 2017, partially offset by a 9.8% decrease in the average cost of purchased power per KWH due to lower natural gas prices in the second quarter 2018 compared to the corresponding period in 2017.firm transportation costs.
Energy purchases from affiliates will vary depending on demand for energy and the availability and cost of generating resources at each company within the Southern Company system. These purchases are made in accordance with the IIC or other contractual agreements, as approved by the FERC.
Other Operations and Maintenance Expenses
Second Quarter 2018 vs. Second Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$13 3.3 $16 2.1
In the second quarter 2018, other operations and maintenance expenses were $402 million compared to $389 million for the corresponding period in 2017. The increase was primarily due to $12 million of expenses from unregulated sales of products and services that were reclassified as other operations and maintenance expenses as a result of the adoption of ASC 606. In prior periods, these expenses were included in other income (expense), net. In addition, distribution costs increased $5 million primarily due to line maintenance. These increases were partially offset by a $4 million decrease in nuclear generation costs primarily due to the timing of plant improvement projects.
For year-to-date 2018, other operations and maintenance expenses were $788 million compared to $772 million for the corresponding period in 2017. The increase was primarily due to $21 million of expenses from unregulated sales of products and services that were reclassified as other operations and maintenance expenses as a result of the adoption of ASC 606. In prior periods, these expenses were included in other income (expense), net. In addition,

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distribution costs increased $11Other Operations and Maintenance Expenses
First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change)
$22 5.7
In the first quarter 2019, other operations and maintenance expenses were $409 million compared to $387 million for the corresponding period in 2018. This increase was primarily due to line maintenance. These increases were partially offset by aof $8 million in environmental expenses, $6 million decrease in property insurancecertain compensation and benefit expenses, and $4 million in nuclear generation expenses primarily due to the receipt of refunds, a $5 million decrease in steam generation costs primarily due to the timing of outages, and a $5 million decrease in nuclear generation costs primarily due to the timing of plant improvement projects.
See Note (A) to the Condensed Financial Statements herein for additional information regarding Alabama Power's adoption of ASC 606.
Depreciation and Amortization
Second Quarter 2018 vs. Second Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$6 3.3 $15 4.1
First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change)
$10 5.3
For year-to-date 2018,In the first quarter 2019, depreciation and amortization was $379$199 million compared to $364$189 million for the corresponding period in 2017.2018. This increase was primarily due to additional plant in service relatedassociated with compliance-related steam, distribution, and transmission.
Other Income (Expense), Net
First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change)
$9 180.0
In the first quarter 2019, other income (expense), net was $14 million compared to steam generation, transmission,$5 million for the corresponding period in 2018. This increase was primarily due to an increase in interest income from temporary cash investments and distribution assets.additional sales of non-utility property in 2019.
Income Taxes
First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change)
$(20) (24.4)
In the first quarter 2019, income taxes were $62 million compared to $82 million for the corresponding period in 2018. This decrease was primarily due to lower pre-tax earnings in the first quarter 2019 compared to the corresponding period in 2018 and the application of the Tax Reform Accounting Order in 2018. See Note 12 to the financial statements of Alabamaunder "Alabama Power under "Depreciation and Amortization"– Tax Reform Accounting Order" in Item 8 of the Form 10-K for additional information.
Allowance for Equity Funds Used During Construction
Second Quarter 2018 vs. Second Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$6 75.0 $11 68.8
In the second quarter 2018, AFUDC equity was $14 million compared to $8 million for the corresponding period in 2017. For year-to-date 2018, AFUDC equity was $27 million compared to $16 million for the corresponding period in 2017. These increases were primarily due to an increase in capital expenditures related to environmental and transmission projects.
Other Income (Expense), Net
Second Quarter 2018 vs. Second Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(3) (20.0) $(10) (40.0)
In the second quarter 2018, other income (expense), net was $12 million compared to $15 million for the corresponding period in 2017. For year-to-date 2018, other income (expense), net was $15 million compared to $25 million for the corresponding period in 2017. These decreases were primarily due to the reclassification of revenues and expenses associated with unregulated sales of products and services to other revenues and operations and maintenance expense, respectively, as a result of the adoption of ASC 606. See Note (A) to the Condensed Financial Statements herein for additional information regarding Alabama Power's adoption of ASC 606.
Income Taxes
Second Quarter 2018 vs. Second Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(87) (57.6) $(132) (47.7)
In the second quarter 2018, income taxes were $64 million compared to $151 million for the corresponding period in 2017. For year-to-date 2018, income taxes were $145 million compared to $277 million for the corresponding period in 2017. These decreases were primarily due to the reduction in the federal income tax rate and the benefit from the flowback of excess deferred income taxes as a result of the Tax Reform Legislation and lower pre-tax net

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income. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory MattersAccounting Order" and Note (H) to the Condensed Financial Statements under "Effective Tax Rate" herein for additional information.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Alabama Power's future earnings potential. The level of Alabama Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Alabama Power's primary business of providing electric service. These factors include Alabama Power's ability to maintain a constructive regulatory environment that continues to allow for the timely recovery of prudently-incurred costs during a time of increasing costs and limited projected demandthe weak pace of growth over the next several years. Future earnings will be impacted byin new customers and electricity use per customer, growth.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

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which could contribute to a net reduction in customer usage. Earnings are subject to a variety of other factors. These factors include weather, competition, new energy contracts with other utilities, energy conservation practiced by customers, the use of alternative energy sources by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in Alabama Power's service territory. Demand for electricity is primarily driven by the pace of economic growth that may be affected by changes in regional and global economic conditions, which may impact future earnings. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Alabama Power in Item 7 of the Form 10-K.
Environmental Matters
Alabama Power's operations are regulated by state and federal environmental agencies through a variety of laws and regulations governing air, water, land, and protection of other natural resources. Alabama Power maintains comprehensive environmental compliance and greenhouse gas (GHG)GHG strategies to assess upcoming requirements and compliance costs associated with these environmental laws and regulations. The costs, including capital expenditures, and operations and maintenance costs, and costs reflected in ARO liabilities, required to comply with environmental laws and regulations and to achieve stated goals may impact future electric generating unit retirement and replacement decisions, results of operations, cash flows, andand/or financial condition. Related costs may result from the installation of additional environmental controls, closure and monitoring of CCR facilities, unit retirements, and adding or changing fuel sources for certain existing units, as well as related upgrades to theAlabama Power's transmission system.and distribution systems. A major portion of these costs areis expected to be recovered through existing ratemaking provisions. The ultimate impact of environmental laws and regulations and the GHG goals discussed below will depend on various factors, such as state adoption and implementation of requirements, the availability and cost of any deployed control technology, 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 fully recovered in rates on a timely basis. Environmental compliance costs are recovered through Rate CNP Compliance. Further, increased costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively affect results of operations, cash flows, andand/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 of Alabama Power under "Environmental Matters" and "Retail Regulatory Matters – Rate CNP Compliance"Remediation" in Item 8 of the Form 10-K for additional information.

FERC Matters
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Environmental Laws and Regulations
Water Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "EnvironmentalNote 2 to the financial statements under "FERC Matters – Environmental Laws and Regulations – Water Quality" of Alabama PowerOpen Access Transmission Tariff" in Item 78 of the Form 10-K for additional information regarding the effluent limitations guidelines (ELG) rule.information.
On March 25, 2019, the Alabama Municipal Electric Authority and Cooperative Energy and SCS and the traditional electric operating companies (including Alabama Power) filed a formal settlement agreement with the FERC agreeing to a rate reduction based on a 10.6% ROE, with a retroactive effective date of May 2,10, 2018, the EPA updated its anticipated final rulemaking schedule for ELG from September 2020 to December 2019. The impact of anyand a five-year moratorium on these parties seeking changes to the ELG rule will depend on the content of the final rule and the outcome of any legal challenges and cannot be determined at this time.
Coal Combustion Residuals
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Coal Combustion Residuals" of Alabama Power in Item 7 of the Form 10-K for additional information regarding the Disposal of Coal Combustion Residuals from Electric Utilities rule (CCR Rule).
On July 30, 2018, the EPA published certain amendments to the CCR Rule, which will be effective August 29, 2018. These amendments extend the date from April 2019 to October 31, 2020 to cease sending CCR and other waste streams to impoundments that demonstrate compliance with all except two specified criteria. These amendments also establish groundwater protection standards for four constituents that do not have established EPA maximum contaminant levels and allow a participating state director or the EPA (where the EPA is the permitting authority) to suspend groundwater monitoring requirements under certain circumstances. Specific site impacts are being evaluated by Alabama Power.
On April 20, 2018, the Alabama Environmental Management Commission approved a state CCR rule that has been provided to the EPA for a six-month review period. This state CCR rule is generally consistent with the federal CCR Rule.OATT formula rate. The ultimate outcome of this matter cannot be determined at this time.
In June 2018, Alabama Power recorded an increase of approximately $1.2 billion to its AROs related totime; however, if approved by the CCR Rule. The revised cost estimatesFERC as of June 30, 2018 are basedfiled, the OATT settlement would not have a material impact on information from feasibility studies performed on ash ponds in use at plants operated by Alabama Power. During the second quarter 2018, Alabama Power's management completed its analysis of these studies which indicated that additional closure costs, primarily related to increases in estimated ash volume, water management requirements, and design revisions, will be required to close these ash ponds under the planned closure-in-place methodology. As further analysis is performed and closure details are developed with respect to ash pond closures, Alabama Power expects to periodically update these cost estimates as necessary. See Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information.
Absent continued recovery of ARO costs through regulated rates, Alabama Power's results of operations, cash flows, and financial condition could be materially impacted. The ultimate outcome of these matters cannot be determined at this time.

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Nuclear Decommissioning
In June 2018, Alabama Power completed an updated decommissioning cost site study for Plant Farley. The estimated cost of decommissioning based on the study resulted in an increase in the ARO liability of approximately $300 million. Amounts previously contributed to the external trust funds are currently projected to be adequate to meet the updated decommissioning obligations. See Note 1 to the financial statements of Alabama Power under "Nuclear Decommissioning" in Item 8 of the Form 10-K and Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" and "Nuclear Decommissioning" herein for additional information.
Global Climate Issues
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues" of Alabama Power in Item 7 of the Form 10-K for additional information.
Through 2017, the Southern Company system has achieved an estimated GHG emission reduction of 36% since 2007. In April 2018, Southern Company established an intermediate goal of a 50% reduction in carbon emissions from 2007 levels by 2030 and a long-term goal of low- to no-carbon operations by 2050. To achieve these goals, the Southern Company system expects to continue growing its renewable energy portfolio, optimize technology advancements to modernize its transmission and distribution systems, increase the use of natural gas for generation, invest in energy efficiency, and continue research and development efforts focused on technologies to lower GHG emissions. The Southern Company system's ability to achieve these goals also will be dependent on many external factors, including supportive national energy policies, low natural gas prices, and the development, deployment, and advancement of relevant energy technologies. The ultimate outcome of this matter cannot be determined at this time.
FERC Matters
Market-Based Rate Authority
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "FERC Matters" of Alabama Power in Item 7 of the Form 10-K for additional information regarding proceedings related to the traditional electric operating companies' (including Alabama Power's) and Southern Power's 2014 and 2017 triennial market power analyses.
On May 4, 2018, the FERC issued an order terminating both proceedings, finding that the traditional electric operating companies (including Alabama Power) and Southern Power satisfy the FERC's standards for market-based rates. On May 9, 2018, the traditional electric operating companies (including Alabama Power) and Southern Power made the compliance filing required by the order. These proceedings are essentially concluded.
Open Access Transmission Tariff
On May 10, 2018, the Alabama Municipal Electric Authority and Cooperative Energy filed with the FERC a complaint against SCS and the traditional electric operating companies (including Alabama Power) claiming that the current 11.25% base ROE used in calculating the annual transmission revenue requirements of the traditional electric operating companies' (including Alabama Power's) open access transmission tariff is unjust and unreasonable as measured by the applicable FERC standards. The complaint requests that the base ROE be set no higher than 8.65% and that the FERC order refunds for the difference in revenue requirements that results from applying a just and reasonable ROE established in this proceeding upon determining the current ROE is unjust and unreasonable. On June 18, 2018, SCS and the traditional electric operating companies (including Alabama Power) filed their response challenging the adequacy of the showing presented by the complainants and offering support for the current ROE. The ultimate outcome of this matter cannot be determined at this time.
Relicensing of Hydroelectric Developments
See BUSINESS – "Regulation – Federal Power Act" in Item 1 of the Form 10-K for a discussion of Alabama
Power's hydroelectric developments on the Coosa River.

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On July 6, 2018, the U.S. Court of Appeals for the District of Columbia Circuit issued a decision vacating the FERC's 2013 order issuing a new 30-year license to Alabama Power for seven hydroelectric developments on the Coosa River and remanding the proceeding to the FERC for further proceedings. Alabama Power continues to operate the Coosa River developments under annual licenses issued by the FERC. The ultimate outcome of this matter cannot be determined at this time.Power.
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

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orders to address current events impacting Alabama Power. See Notes 1 and 3Note 2 to the financial statements of Alabama Power under "Nuclear Outage Accounting Order" and "Retail Regulatory Matters," respectively,"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.
On May 1, 2018, the Alabama PSC approved modificationsEnvironmental Accounting Order
In connection with management's decision to Rate RSE and other commitments designed to positionretire Plant Gorgas, in February 2019, Alabama Power reclassified approximately $1.3 billion for Plant Gorgas Unit 10 from plant in service, net of depreciation to addressother utility plant, net and continued to depreciate the growing pressure on its credit quality resulting fromasset according to the Tax Reform Legislation, without increasing retail rates under Rate RSE in the near term.original depreciation rates. On April 15, 2019, Alabama Power plans to reduce growth in total debt by increasing equity, with corresponding reductions in debt issuances, thereby de-leveraging its capital structure. Alabama Power's goal is to achieve an equity ratio ofretired Plant Gorgas Units 8, 9, and 10 and reclassified approximately 55% by the end of 2025. At June 30, 2018, Alabama Power's equity ratio was approximately 46.6%. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters – Federal Tax Reform Legislation" of Alabama Power in Item 7$740 million of the Form 10-K for additional information.
Rate RSE
The approved modifications to Rate RSE became effective June 2018 and are applicable for January 2019 billings and thereafter. The modifications include reducing the topremaining net investment costs of the allowed weighted common equity return (WCER) range from 6.21%units to 6.15% and modificationsa regulatory asset to be recovered over the units' remaining useful lives as established prior to the refund mechanism applicabledecision to prior year actual results. The modifications to the refund mechanism allow Alabama Power to retain a portionretire. Additionally, approximately $700 million of the revenue that causes the actual WCER for a given year to exceed the allowed range.
In conjunction with these modifications to Rate RSE, on May 8, 2018, Alabama Power consentednet capitalized asset retirement costs will be reclassified to a moratorium on any upward adjustments under Rate RSE for 2019regulatory asset and 2020. Additionally, Alabama Power will return $50 million to customers through bill creditsrecovered in 2019.
In accordance with an established retail tariff that provides for an interim adjustment to customer billings to recognize the impact of a change in the statutory income tax rate, Alabama Power is returning approximately $257 million to retail customers through bill credits in the second half of 2018 as a result of the change in the federal income tax rate under the Tax Reform Legislation.
Rate ECR
On May 1, 2018, the Alabama PSC approved an increase to Rate ECR from 2.015 cents per KWH to 2.353 cents per KWH effective July 2018 which is expected to result in additional collections of approximately $100 million through December 31, 2018. The approved increase in the Rate ECR factor will have no significant effect on Alabama Power's net income, but will increase operating cash flows related to fuel cost recovery in 2018. The rate will return to 5.910 cents per KWH in 2019, absent a further order from the Alabama PSC.
Accounting Order
On May 1, 2018, the Alabama PSC approved an accounting order that authorizes Alabama Power to defer the benefits of federal excess deferred income taxes associated with the Tax Reform Legislation for the year ending December 31, 2018 as a regulatory liability and to use up to $30 million of such deferrals to offset under recovered

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amounts under Rate ECR. Any remaining amounts will be used for the benefit of customers as determinedguidance provided by the Alabama PSC. As of June 30, 2018, Alabama Power had applied approximately $30 million of such deferrals to offset the under recovered balance under Rate ECR and expects the total deferrals for the year ending December 31, 2018 to be approximately $50 million. See Note 52 to the financial statements of Alabamaunder "Alabama Power under "Federal Tax Reform Legislation"– Environmental Accounting Order" and "Current and Deferred Income Taxes"Note 6 in Item 8 of the Form 10-K for additional information.
Plant Greene County
Alabama Power jointly owns Plant Greene County with an affiliate, Mississippi Power. See Note 4 to the financial statements of Alabama Power in Item 8 of the Form 10-K for additional information regarding the joint ownership agreement. On August 6, 2018, Mississippi Power filed its proposed Reserve Margin Plan (RMP) with the Mississippi PSC, which proposes a 4-year acceleration of the retirement of Plant Greene County Units 1 and 2 to the third quarter 2021 and the third quarter 2022, respectively. Mississippi Power's proposed Plant Greene County unit retirements would require the completion of proposed transmission and system reliability improvements, as well as agreement by Alabama Power. Alabama Power will monitor Mississippi Power's proposed RMP and associated regulatory process as well as the proposed transmission and system reliability improvements. Alabama Power will review all the facts and circumstances and will evaluate all its alternatives prior to reaching a final determination on the ongoing operations of Plant Greene County. The ultimate outcome of this matter cannot be determined at this time.
Income Tax Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters" of Alabama Power in Item 7 of the Form 10-K and FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk," Note (B) to the Condensed Financial Statements under "Regulatory MattersAlabama Power," and Note (H) to the Condensed Financial Statements herein for information regarding the Tax Reform Legislation and related regulatory actions.
Other Matters
Alabama Power is involved in various other matters that could affect future earnings, including matters being litigated and regulatory matters that could affect future earnings.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 predicted at this time; however, for current proceedings not specifically reported in NoteNotes (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 NoteNotes (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.
On March 2, 2018, the Alabama Department of Environmental Management (ADEM) issued proposed administrative orders assessing a penalty of $1.25 million to Alabama Power for unpermitted discharge of fluids and/or pollutants to groundwater at five electric generating plants. The proposed orders also require the submission to the ADEM of a plan with a schedule for implementation of a comprehensive groundwater investigation, including an assessment of corrective measures, a report evaluating any deficiencies at the facilities that may have led to the

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unpermitted discharges, and quarterly progress reports. Alabama Power is awaiting finalization of the orders. The ultimate outcome of this matter cannot be determined at this time.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Alabama Power prepares its financial statements in accordance with GAAP. Significant accounting policies are described in NoteNotes 1, 5, and 6 to the financial statements of Alabama Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Alabama Power's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Alabama Power in Item 7 of the Form 10-K for a complete discussion of Alabama Power's critical accounting policies and estimates.
Recently Issued Accounting Standards
See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Recently Issued Accounting Standards" of Alabama Power in Item 7 of the Form 10-K for additional information regarding ASU No. 2016-02, Leases (Topic 842). See Note (A) to the Condensed Financial Statements herein for information regarding Alabama Power's recently adopted accounting standards.

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FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Alabama Power in Item 7 of the Form 10-K for additional information. Alabama Power's financial condition remained stable at June 30, 2018.March 31, 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 $652$146 million for the first sixthree months of 2018,2019, a decrease of $20$9 million as compared to the first sixthree months of 2017.2018. The decrease in net cash provided from operating activities was primarily due to decreased fuel cost recovery and the timing of vendor payments. These uses of cash werepayments and other current liabilities, partially offset by an increase in other current liabilities due to the timing of customer billing reductions related to the Tax Reform Legislation and income tax refunds in 2018.increased fuel cost recovery. Net cash used for investing activities totaled $1.08 billion$511 million for the first sixthree months of 20182019 primarily due to gross property additions related to additional capital expenditures for distribution, environmental, distribution, and transmission assets. Net cash provided from financing activities totaled $565$811 million for the first sixthree months of 20182019 primarily due to an issuance of long-term debt and additional capital contributions from Southern Company, partially offset by a payment of common stock dividend payments.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 sixthree months of 20182019 include increases of $2.1$1.2 billion in property, plant, and equipmenttotal common stockholder's equity, primarily due to increases in AROs related to the CCR Rule and additions to distribution, environmental, and transmission assets, $1.4a $1.225 billion in AROs related to the CCR Rule and nuclear decommissioning, $494 million in additional paid-in capital due to capital contributionscontribution from Southern Company, $294and $446 million in long-term debtcash and cash equivalents. Other significant changes include decreases of $268 million in other accounts payable primarily due to the issuancetiming of additional senior notes,vendor payments and $200 million in securities due within one year reclassified fromdue to the maturity of long-term debt. See Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information related to changes in Alabama Power's AROs.

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Capital Requirements and Contractual Obligations
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Alabama Power in Item 7 of the Form 10-K for a description of Alabama Power's capital requirements and contractual obligations. Approximately $200 million will be required through June 30, 2019 to fundThere are no scheduled maturities of long-term debt.debt through March 31, 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.
Alabama Power anticipates costs associated with closure-in-place and monitoring of ash ponds in accordance with the CCR Rule, which are reflected in Alabama Power's ARO liabilities. These costs, which are expected to change as Alabama Power continues to refine its assumptions underlying the cost estimates and evaluate the method and timing of compliance activities, are expected to begin in 2019 and are currently estimated to be approximately $232 million for 2019, $238 million for 2020, $246 million for 2021, and $252 million for 2022. See Note 1 to the financial statements of Alabama Power under "Asset Retirement Obligations and Other Costs of Removal" in Item 8 of the Form 10-K, FUTURE EARNINGS POTENTIAL – "Environmental Matters– Environmental Laws and Regulations – Coal Combustion Residuals" herein, and Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information.
The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental laws and regulations; the outcome of any legal challenges to environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing generating units, to meet regulatory requirements; changes in the expected environmental compliance program; changes in FERC rules and regulations; Alabama PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.
Sources of Capital
Alabama Power plans to obtain the funds to meet its future capital needs from sources similar to those used in the past, which were primarily from operating cash flows, external security issuances, borrowings from financial institutions, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. In January 2019, Alabama Power received a capital contribution totaling $1.225 billion from Southern Company. See

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MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Alabama Power in Item 7 of the Form 10-K for additional information.
Alabama Power's current liabilities sometimes exceed current assets because of long-term debt maturities and the periodic use of short-term debt as a funding source, as well as significant seasonal fluctuations in cash needs.
At June 30, 2018,March 31, 2019, Alabama Power had approximately $686$759 million of cash and cash equivalents. Committed credit arrangements with banks at June 30, 2018March 31, 2019 were as follows:
ExpiresExpires     Expires Within One YearExpires    
2018 2019 2020 2022 Total Unused Term Out No Term Out
20192019 2020 2022 Total Unused
(in millions)
$2
 $31
 $500
 $800
 $1,333
 $1,333
 $
 $33
33
 $500
 $800
 $1,333
 $1,333
See Note 68 to the financial statements of Alabama Power under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.

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Most of these bank credit arrangements, as well as Alabama Power's term loan arrangements, contain covenants that limit debt levels and contain cross-acceleration provisions to other indebtedness (including guarantee obligations) of Alabama Power. Such cross-acceleration provisions to other indebtedness would trigger an event of default if Alabama Power defaulted on indebtedness, the payment of which was then accelerated. At June 30, 2018,March 31, 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, 2018.March 31, 2019. At June 30, 2018,March 31, 2019, Alabama Power had $120$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.
Details of short-term borrowings were as follows:
 
Short-term Debt at
June 30, 2018
 
Short-term Debt During the Period(*)
 Amount Outstanding Weighted Average Interest Rate Average
Amount Outstanding
 Weighted
Average
Interest
Rate
 Maximum
Amount
Outstanding
 (in millions)   (in millions)   (in millions)
Commercial paper$
 % $44
 2.2% $245
Short-term bank loan3
 3.7% 3
 3.7% 3
Total$3
 3.7% $47
 2.3%  
 
Short-term Debt During the Period(*)
 Average
Amount Outstanding
 Weighted
Average
Interest
Rate
 Maximum
Amount
Outstanding
 (in millions)   (in millions)
Commercial paper$32
 2.7% $185
(*)Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 2018.March 31, 2019. No short-term debt was outstanding at March 31, 2019.

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Alabama Power believes the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and operating cash flows.
Credit Rating Risk
At June 30, 2018,March 31, 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.

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The At March 31, 2019, the maximum potential collateral requirements under these contracts at June 30, 2018 were as follows:
Credit Ratings
Maximum Potential
Collateral
Requirements
 (in millions)
At BBB and/or Baa2$1
At BBB- and/or Baa3$1
Below BBB- and/or Baa3$279
a rating below BBB- and/or Baa3 totaled approximately $354 million.
Included in these amounts are certain agreements that could require collateral in the event that either Alabama Power or Georgia Power (affiliate company(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 32 to the financial statements of Alabamaunder "Alabama Power under "Retail Regulatory Matters – Rate RSE" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory MattersAlabama PowerRate RSE" herein for additional information.
Financing Activities
In June 2018,February 2019, Alabama Power issued $500repaid at maturity $200 million aggregate principal amount of Series 2018A 4.30%Z 5.125% Senior Notes due JulyFebruary 15, 2048. The proceeds were used to repay outstanding commercial paper and for general corporate purposes, including Alabama Power's continuous construction program.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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GEORGIA POWER COMPANY

GEORGIA POWER COMPANY
CONDENSED STATEMENTS OF INCOME (UNAUDITED)

 For the Three Months
Ended June 30,
 For the Six Months
Ended June 30,
 2018 2017 2018 2017
 (in millions) (in millions)
Operating Revenues:       
Retail revenues$1,889
 $1,904
 $3,688
 $3,593
Wholesale revenues, non-affiliates36
 40
 80
 79
Wholesale revenues, affiliates3
 9
 13
 17
Other revenues120
 95
 227
 191
Total operating revenues2,048
 2,048
 4,008
 3,880
Operating Expenses:       
Fuel378
 445
 790
 815
Purchased power, non-affiliates111
 103
 233
 191
Purchased power, affiliates178
 138
 349
 310
Other operations and maintenance457
 417
 863
 816
Depreciation and amortization230
 223
 458
 444
Taxes other than income taxes106
 101
 214
 199
Estimated loss on Plant Vogtle Units 3 and 41,060
 
 1,060
 
Total operating expenses2,520
 1,427
 3,967
 2,775
Operating Income (Loss)(472) 621
 41
 1,105
Other Income and (Expense):       
Interest expense, net of amounts capitalized(102) (104) (208) (205)
Other income (expense), net35
 34
 73
 71
Total other income and (expense)(67) (70) (135) (134)
Earnings (Loss) Before Income Taxes(539) 551
 (94) 971
Income taxes (benefit)(143) 199
 (50) 355
Net Income (Loss)(396) 352
 (44) 616
Dividends on Preferred and Preference Stock
 5
 
 9
Net Income (Loss) After Dividends
   on Preferred and Preference Stock
$(396) $347
 $(44) $607
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

 For the Three Months
Ended June 30,
 For the Six Months
Ended June 30,
 2018 2017 2018 2017
 (in millions) (in millions)
Net Income (Loss)$(396) $352
 $(44) $616
Other comprehensive income (loss):       
Qualifying hedges:       
Reclassification adjustment for amounts included in net income,
net of tax of $-, $-, $1, and $1, respectively
1
 1
 2
 2
Total other comprehensive income (loss)1
 1
 2
 2
Comprehensive Income (Loss)$(395) $353
 $(42) $618
The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.

GEORGIA POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
 For the Six Months
Ended June 30,
 2018 2017
 (in millions)
Operating Activities:   
Net income (loss)$(44) $616
Adjustments to reconcile net income (loss) to net cash provided from operating activities —   
Depreciation and amortization, total562
 543
Deferred income taxes(256) 159
Allowance for equity funds used during construction(32) (25)
Deferred expenses34
 41
Pension, postretirement, and other employee benefits(47) (45)
Settlement of asset retirement obligations(49) (62)
Estimated loss on Plant Vogtle Units 3 and 41,060
 
Other, net27
 (39)
Changes in certain current assets and liabilities —   
-Receivables(103) (150)
-Fossil fuel stock38
 (32)
-Prepaid income taxes115
 (4)
-Other current assets25
 (18)
-Accounts payable(87) (153)
-Accrued taxes(89) (194)
-Accrued compensation(56) (65)
-Retail fuel cost over recovery
 (84)
-Other current liabilities(26) (6)
Net cash provided from operating activities1,072
 482
Investing Activities:   
Property additions(1,501) (1,284)
Nuclear decommissioning trust fund purchases(440) (271)
Nuclear decommissioning trust fund sales435
 266
Cost of removal, net of salvage(50) (32)
Change in construction payables, net of joint owner portion86
 1
Payments pursuant to LTSAs(46) (56)
Asset dispositions134
 63
Other investing activities(11) (12)
Net cash used for investing activities(1,393) (1,325)
Financing Activities:   
Increase in notes payable, net480
 37
Proceeds —   
Capital contributions from parent company1,502
 380
Senior notes
 850
Short-term borrowings
 800
Redemptions and repurchases —   
Senior notes(1,000) (450)
Pollution control revenue bonds(398) (27)
Short-term borrowings(150) 
Other long-term debt(100) 
Payment of common stock dividends(691) (640)
Premiums on redemption and repurchases of senior notes(152) 
Other financing activities(11) (19)
Net cash provided from (used for) financing activities(520) 931
Net Change in Cash, Cash Equivalents, and Restricted Cash(841) 88
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period852
 3
Cash, Cash Equivalents, and Restricted Cash at End of Period$11
 $91
Supplemental Cash Flow Information:   
Cash paid during the period for —   
Interest (net of $12 and $11 capitalized for 2018 and 2017, respectively)$211
 $186
Income taxes, net64
 213
Noncash transactions — Accrued property additions at end of period669
 348
The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.

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


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

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SECOND QUARTER 2018 vs. SECOND QUARTER 2017
AND
YEAR-TO-DATE 2018 vs. YEAR-TO-DATE 2017


OVERVIEW
Georgia Power operates as a vertically integrated utility providing electric service to retail customers within its traditional service territory located within the State of Georgia and to wholesale customers in the Southeast.
Many factors affect the opportunities, challenges, and risks of Georgia Power's business of providing electric service. These factors include the ability to maintain a constructive regulatory environment, to maintain and grow energy sales, and to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand growth, stringent environmental standards, reliability, fuel, capital expenditures, and restoration following major storms. Georgia Power has various regulatory mechanisms that operate to address cost recovery. Effectively operating pursuant to these regulatory mechanisms and appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Georgia Power for the foreseeable future. On April 3, 2018, the Georgia PSC approved a settlement agreement between Georgia Power and the staff of the Georgia PSC regarding the retail rate impact of the Tax Reform Legislation (Tax Reform Settlement Agreement). The Tax Reform Settlement Agreement provides for a total of $330 million in customer refunds for 2018 and 2019 and the deferral of certain revenues and tax benefits to be addressed in Georgia Power's next base rate case, which is expected to be filed by July 1, 2019. The Georgia PSC also approved an increase to Georgia Power's retail equity ratio to address the negative cash flow and credit metric impacts of the Tax Reform Legislation. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory MattersRate Plans" herein for additional information on the Tax Reform Settlement Agreement.
Georgia Power continues to focus on several key performance indicators including, but not limited to, customer satisfaction, plant availability, system reliability, the execution of major construction projects, and net income.
Plant Vogtle Units 3 and 4 Status
In 2009, the Georgia PSC certified construction of Plant Vogtle Units 3 and 4 (with electric generating capacity of approximately 1,100 MWs each). In March 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. In December 2017, the Georgia PSC approved Georgia Power's recommendation to continue construction.
In the second quarter 2018, Georgia Power revised its base cost forecast and estimated contingency to complete construction and start-up of Plant Vogtle Units 3 and 4 to $8.0 billion and $0.4 billion, respectively, for a total project capital cost forecast of $8.4 billion (net of $1.7 billion received under the Guarantee Settlement Agreement and $188 million in Customer Refunds recognized as a regulatory liability in 2017). Although Georgia Power believes these incremental costs are reasonable and necessary to complete the project and the Georgia PSC has stated the $7.3 billion estimate included in the seventeenth VCM proceeding does not represent a cost cap, Georgia Power does not intend to seek rate recovery for the $0.7 billion increase in costs included in the revised base capital cost forecast, which will be filed with the Georgia PSC in the nineteenth VCM report on August 31, 2018. In connection with future VCM filings, Georgia Power may request the Georgia PSC to evaluate costs included in the revised construction contingency estimate for rate recovery as and when they are appropriately included in the base capital cost forecast. After considering the significant level of uncertainty that exists regarding the future recoverability of costs included in the construction contingency estimate since the ultimate outcome of these matters is subjectSee Note 2 to the outcome of future assessments by management, as well as Georgia PSC decisions in these future regulatory proceedings, Georgia Power has recorded a total pre-tax charge to income of $1.1 billion ($0.8 billion after tax) as of June 30, 2018.

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As a result of the increase in the total project capital cost forecast and Georgia Power's decision not to seek rate recovery of the increase in the base capital costs, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction. The Vogtle Owners are expected to conduct these votes in the third quarter 2018.
If the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 do not vote to continue construction, the Vogtle Joint Ownership Agreements provide that the project will be cancelled, and construction will cease. In the event that fewer than 90% of the Vogtle Owners vote to continue construction, Georgia Power and the other Vogtle Owners will assess options for Plant Vogtle Units 3 and 4. If Plant Vogtle Units 3 and 4 were cancelled and Georgia Power was unable to recover costs it has incurred in connection with the project, Georgia Power's results of operations, cash flow, and financial condition would be materially impacted. The ultimate outcome of this matter cannot be determined at this time.
Georgia Power's revised cost estimate reflects an expected in-service date of November 2021 for Unit 3 and November 2022 for Unit 4.
See FUTURE EARNINGS POTENTIAL – "Retail Regulatory MattersNuclear Construction" and ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" herein for additional information on Plant Vogtle Units 3 and 4.
RESULTS OF OPERATIONS
Net Income (Loss)
Second Quarter 2018 vs. Second Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(743) N/M $(651) N/M
N/M - Not meaningful
Georgia Power's net loss after dividends on preferred and preference stock for the second quarter 2018 was $396 million compared to net income after dividends on preferred and preference stock of $347 million for the corresponding period in 2017. For year-to-date 2018, net loss after dividends on preferred and preference stock was $44 million compared to net income after dividends on preferred and preference stock of $607 million for the corresponding period in 2017. The changes were primarily due to a $1.1 billion ($0.8 billion after tax) charge in the second quarter 2018 for an estimated probable loss related to Georgia Power's construction of Plant Vogtle Units 3 and 4, revenues deferred as a regulatory liability for future customer refunds related to the Tax Reform Legislation, and higher non-fuel operations and maintenance expenses. Partially offsetting the changes were lower federal income tax expense as a result of the Tax Reform Legislation and an increase in retail revenues associated with warmer weather in the second quarter 2018 compared to the corresponding period in 2017. Also offsetting the change for year-to-date 2018 was an increase in retail revenues associated with colder weather in the first quarter 2018 compared to the corresponding period in 2017. See Note (B) to the Condensed Financial Statements under "Nuclear Construction" herein for additional information on the estimated loss related to Georgia Power's construction of Plant Vogtle Units 3 and 4.
Retail Revenues
Second Quarter 2018 vs. Second Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(15) (0.8) $95 2.6
In the second quarter 2018, retail revenues were $1.89 billion compared to $1.90 billion for the corresponding period in 2017. For year-to-date 2018, retail revenues were $3.69 billion compared to $3.59 billion for the corresponding period in 2017.

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Details of the changes in retail revenues were as follows:
 Second Quarter 2018 Year-to-Date 2018
 (in millions) (% change) (in millions) (% change)
Retail – prior year$1,904
   $3,593
  
Estimated change resulting from –       
Rates and pricing(58) (3.0) (108) (3.0)
Sales growth3
 0.1
 26
 0.7
Weather40
 2.1
 105
 2.9
Fuel cost recovery
 
 72
 2.0
Retail – current year$1,889
 (0.8)% $3,688
 2.6 %
Revenues associated with changes in rates and pricing decreased in the second quarter and year-to-date 2018 when compared to the corresponding periods in 2017 primarily due to revenues deferred as a regulatory liability for future customer refunds related to the Tax Reform Legislation and a decrease in revenues related to the recovery of Plant Vogtle Units 3 and 4 construction financing costs under the NCCR tariff, also primarily related to the Tax Reform Legislation. Also contributing to the year-to-date 2018 decrease was the rate pricing effect of increased customer usage in the first quarter 2018. The decreases were partially offset by higher contributions from variable demand-driven pricing from commercial and industrial customers. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory MattersRate Plans" herein for additional information on regulatory actions related to the Tax Reform Legislation. Also, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Nuclear Construction" of Georgia Powerstatements in Item 78 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Retail Regulatory MattersNuclear ConstructionRegulatory Matters" herein for additional information related to the NCCR tariff.
Revenues attributable to changes in sales increased in the second quarter and year-to-date 2018 when compared to the corresponding periods in 2017. Weather-adjusted residential KWH sales were essentially flat for the second quarter 2018 and increased 1.1% for year-to-date 2018 largely due to customer growth. Weather-adjusted commercial KWH sales increased 0.7% and 1.5% for the second quarter and year-to-date 2018, respectively, largely due to customer growth. Weather-adjusted industrial KWH sales increased slightly in the second quarter 2018 and increased 0.5% for year-to-date 2018, primarily due to increased demand in the stone, clay, and glass, rubber, and textiles sectors. The increase in weather-adjusted industrial KWH sales for year-to-date 2018 was partially offset by decreased demand in the paper sector.
Fuel revenues and costs are allocated between retail and wholesale jurisdictions. In the second quarter 2018, retail fuel cost recovery revenues remained flat when compared to the corresponding period in 2017 primarily due to increased energy sales driven by warmer weather and higher purchased power costs, largely offset by lower natural gas prices. For year-to-date 2018, retail fuel cost recovery revenues increased $72 million when compared to the corresponding period in 2017 primarily due to increased energy sales driven by colder weather in the first quarter 2018 and warmer weather in the second quarter 2018 and higher purchased power costs. Electric rates include provisions to periodically adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these fuel cost recovery provisions, fuel revenues generally equal fuel expenses and do not affect net income. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Fuel Cost Recovery" of Georgia Power in Item 7 of the Form 10-K for additional information.

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Wholesale Revenues – Affiliates
Second Quarter 2018 vs. Second Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(6) (66.7) $(4) (23.5)
Wholesale revenues from sales to affiliated companies will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost.
In the second quarter 2018, wholesale revenues from sales to affiliates were $3 million compared to $9 million for the corresponding period in 2017. For year-to-date 2018, wholesale revenues from sales to affiliates were $13 million compared to $17 million for the corresponding period in 2017. The decreases were due to 67.1% and 57.9% decreases in KWH sales in the second quarter and year-to-date 2018, respectively, primarily due to the higher cost of Georgia Power-owned generation as compared to the market cost of available energy.
Other Revenues
Second Quarter 2018 vs. Second Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$25 26.3 $36 18.8
In the second quarter 2018, other revenues were $120 million compared to $95 million for the corresponding period in 2017. For year-to-date 2018, other revenues were $227 million compared to $191 million for the corresponding period in 2017. The increases were primarily due to $23 million and $38 million of revenues in the second quarter and year-to-date 2018, respectively, primarily from unregulated sales of products and services that were reclassified as other revenues as a result of the adoption of ASC 606, Revenue from Contracts with Customers (ASC 606). In prior periods, these revenues were included in other income (expense), net. See Note (A)(B) to the Condensed Financial Statements herein for additional information regarding Georgia Power's adoption of ASC 606.information.
Fuel Cost Recovery
The traditional electric operating companies each have established fuel cost recovery rates approved by their respective state PSCs. Fuel cost recovery revenues are adjusted for differences in actual recoverable fuel costs and Purchased Power Expenses
 Second Quarter 2018
vs.
Second Quarter 2017
 Year-to-Date 2018 vs. Year-to-Date 2017
 (change in millions) (% change) (change in millions) (% change)
Fuel$(67) (15.1) $(25) (3.1)
Purchased power – non-affiliates8
 7.8
 42
 22.0
Purchased power – affiliates40
 29.0
 39
 12.6
Total fuel and purchased power expenses$(19)   $56
  
In the second quarter 2018, total fuel and purchased power expenses were $667 million compared to $686 millionamounts billed in current regulated rates. Accordingly, changes in the corresponding period in 2017. The decrease was primarily due to a $37 million decrease related to the average cost of fuel and purchased power primarily due to lower natural gas prices and a $49 million decrease related to the volume of KWHs generated due to scheduled generation outages, partially offset by an increase of $67 million related to the volume of KWHs purchased due to warmer weather.
For year-to-date 2018, total fuel and purchased power expenses were $1.37 billion compared to $1.32 billion in the corresponding period in 2017. The increase was primarily due to a $32 million increase related to the volume of KWHs generated and purchased due to colder weather in the first quarter 2018 and warmer weather in the second quarter 2018 and a $28 million increase related to the average cost of purchased power primarily due to higher

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energy prices, partially offset by a $4 million decrease related to the average cost of fuel due to lower natural gas prices in the second quarter 2018.
Fuel and purchased power energy transactions dobilling factor will not have a significant impacteffect on earnings since theseSouthern Company's revenues or net income, but will affect cash flow. The traditional electric operating companies continuously monitor their under or over recovered fuel expenses are generally offset by fuel revenues through Georgia Power'scost balances and make appropriate filings with their state PSCs to adjust fuel cost recovery mechanism. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Fuel Cost Recovery" of Georgiarates as necessary.
Alabama Power in Item 7
Alabama Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Form 10-K for additional information.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.
Details of Georgia Power's generation and purchased power were as follows:
 Second Quarter 2018 Second Quarter 2017 Year-to-Date 2018 Year-to-Date 2017
Total generation (in billions of KWHs)
15 16 31 30
Total purchased power (in billions of KWHs)
8 6 14 13
Sources of generation (percent) —
       
Gas40 37 42 41
Coal29 36 29 32
Nuclear28 25 26 25
Hydro3 2 3 2
Cost of fuel, generated (in cents per net KWH) 
       
Gas2.61 2.75 2.67 2.76
Coal3.26 3.20 3.31 3.23
Nuclear0.83 0.84 0.83 0.84
Average cost of fuel, generated (in cents per net KWH)
2.30 2.43 2.37 2.41
Average cost of purchased power (in cents per net KWH)(*)
4.37 4.76 4.81 4.61
(*)Average cost of purchased power includes fuel purchased by Georgia Power for tolling agreements where power is generated by the provider.
FuelEnvironmental Accounting Order
In connection with management's decision to retire Plant Gorgas, in February 2019, Alabama Power reclassified approximately $1.3 billion for Plant Gorgas Unit 10 from plant in service, net of depreciation to other utility plant, net and continued to depreciate the second quarter 2018, fuel expense was $378asset according to the original depreciation rates. On April 15, 2019, Alabama Power retired Plant Gorgas Units 8, 9, and 10 and reclassified approximately $740 million compared to $445 million inof the corresponding period in 2017. The decrease was primarily dueremaining net investment costs of the units to a 9.3% decrease inregulatory asset to be recovered over the volumeunits' remaining useful lives as established prior to the decision to retire. Additionally, approximately $700 million of KWHs generated largely due to scheduled generation outages and a 5.4% decrease in the average cost of fuel per KWH generated primarily due to lower natural gas prices.
For year-to-date 2018, fuel expense was $790 million compared to $815 million in the corresponding period in 2017. The decrease was primarily duenet capitalized asset retirement costs will be reclassified to a 7.3% decrease in the volume of KWHs generated by coal largely due to scheduled generation outagesregulatory asset and a 3.3% decrease in the average cost of fuel per KWH generated by natural gas, partially offset by a 2.5% increase in the average cost of fuel per KWH generated by coal.
Purchased Power – Non-Affiliates
In the second quarter 2018, purchased power expense from non-affiliates was $111 million compared to $103 million in the corresponding period in 2017. The increase was primarily due to a 3.6% increase in the average cost per KWH purchased primarily due to higher energy prices and a 1.9% increase in the volume of KWHs purchased primarily due to scheduled generation outages and warmer weather.
For year-to-date 2018, purchased power expense from non-affiliates was $233 million compared to $191 million in the corresponding period in 2017. The increase was primarily due to an 11.4% increase in the volume of KWHs purchased due to colder weather in the first quarter 2018, warmer weather in the second quarter 2018, and

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scheduled generation outages and a 10.5% increase in the average cost per KWH purchased due to higher energy prices.
Energy purchases from non-affiliates will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation.
Purchased Power – Affiliates
In the second quarter 2018, purchased power expense from affiliates was $178 million compared to $138 million in the corresponding period in 2017. The increase was primarily due to a 31.4% increase in the volume of KWHs purchased due to scheduled generation outages and warmer weather, partially offset by an 11.6% decrease in the average cost per KWH purchased primarily resulting from lower energy prices.
For year-to-date 2018, purchased power expense from affiliates was $349 million compared to $310 million in the corresponding period in 2017. The increase was primarily due to a 2.4% increase in the volume of KWHs purchased due to colder weather in the first quarter 2018 and scheduled generation outages and warmer weather in the second quarter 2018.
Energy purchases from affiliates will vary depending on demand and the availability and cost of generating resources at each company within the Southern Company system. These purchases are maderecovered in accordance with the IIC or other contractual agreements, all as approvedaccounting guidance provided by the FERC.
Other Operations and Maintenance Expenses
Second Quarter 2018 vs. Second Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$40 9.6 $47 5.8
In the second quarter 2018, other operations and maintenance expenses were $457 million compared to $417 million in the corresponding period in 2017. The increase was primarily due to $20 million of expenses from unregulated sales of products and services that were reclassified as other operations and maintenance expenses as a result of the adoption of ASC 606. In prior periods, these expenses were included in other income (expense), net. Also contributing to the increase were $8 million related to the timing of scheduled generation outage costs, $5 million primarily related to the timing of distribution overhead and underground line maintenance, $4 million in demand-side management costs related to the timing of new programs, and $3 million in billing adjustments with integrated transmission system owners, partially offset by a decrease of $7 million associated with an employee attrition plan.
For year-to-date 2018, other operations and maintenance expenses were $863 million compared to $816 million in the corresponding period in 2017. The increase was primarily due to $35 million of expenses from unregulated sales of products and services that were reclassified as other operations and maintenance expenses as a result of the adoption of ASC 606. In prior periods, these expenses were included in other income (expense), net. Also contributing to the increase were a $19 million decrease in gains from sales of integrated transmission system assets and an $11 million increase in demand-side management costs related to the timing of new programs, partially offset by decreases of $10 million related to affiliate labor billing adjustments and $6 million associated with an employee attrition plan.
Alabama PSC. See Note (A) to the Condensed Financial Statements herein for additional information regarding Georgia Power's adoption of ASC 606.

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Depreciation and Amortization
Second Quarter 2018 vs. Second Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$7 3.1 $14 3.2
In the second quarter 2018, depreciation and amortization was $230 million compared to $223 million in the corresponding period in 2017. For year-to-date 2018, depreciation and amortization was $458 million compared to $444 million in the corresponding period in 2017. The increases were primarily due to increases of $8 million and $15 million related to additional plant in service in the second quarter and year-to-date 2018, respectively.
Taxes Other Than Income Taxes
Second Quarter 2018 vs. Second Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$5 5.0 $15 7.5
In the second quarter 2018, taxes other than income taxes were $106 million compared to $101 million in the corresponding period in 2017. For year-to-date 2018, taxes other than income taxes were $214 million compared to $199 million in the corresponding period in 2017. The increases were primarily due to increases in property taxes of $4 million and $7 million in the second quarter and year-to-date 2018, respectively, as a result of an increase in the assessed value of property. Also contributing to the increase for year-to-date 2018 was a $7 million increase in municipal franchise fees largely related to higher retail revenues.
Estimated Loss on Plant Vogtle Units 3 and 4
Second Quarter 2018 vs. Second Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$1,060 N/M $1,060 N/M
N/M - Not meaningful
In the second quarter 2018, an estimated probable loss of $1.1 billion was recorded to reflect Georgia Power's revised estimate to complete construction and start-up of Plant Vogtle Units 3 and 4, which reflects the increase in costs included in the revised base capital cost forecast for which Georgia Power does not intend to seek rate recovery and costs included in the revised construction contingency estimate for which Georgia Power may seek rate recovery as and when such costs are appropriately included in the base capital cost forecast. See Note (B) to the Condensed Financial Statements under "Nuclear Construction" herein for additional information.
Income Taxes (Benefit)
Second Quarter 2018 vs. Second Quarter 2017
Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)
(% change)
(change in millions) (% change)
$(342)
N/M
$(405) N/M
N/M - Not meaningful
In the second quarter 2018, income tax benefit was $143 million compared to income tax expense of $199 million in the corresponding period in 2017. For year-to-date 2018, income tax benefit was $50 million compared to income tax expense of $355 million in the corresponding period in 2017. The changes were primarily due to the reduction in pre-tax earnings (loss) resulting from the estimated probable loss related to Plant Vogtle Units 3 and 4 and a lower federal income tax rate as a result of the Tax Reform Legislation. See Note (B) to the Condensed Financial Statements under "Nuclear Construction" herein for additional information on the estimated loss related to Georgia

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Power's construction of Plant Vogtle Units 3 and 4. Also, see Note (H) to the Condensed Financial Statements under "Effective Tax Rate" herein for additional information on the Tax Reform Legislation.
Dividends on Preferred and Preference Stock
Second Quarter 2018 vs. Second Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(5) (100.0) $(9) (100.0)
In the second quarter and year-to-date 2018, there were no dividends on preferred and preference stock compared to $5 million and $9 million, respectively, in the corresponding periods in 2017. The decreases were due to the redemption in October 2017 of all outstanding shares of Georgia Power's preferred and preference stock. See Note 62 to the financial statements of Georgiaunder "Alabama Power under "Outstanding Classes of Capital Stock"– Environmental Accounting Order" and Note 6 in Item 8 of the Form 10-K for additional information.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Georgia Power's future earnings potential. The level of Georgia Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Georgia Power's business of providing electric service. These factors include Georgia Power's ability to maintain a constructive regulatory environment that continues to allow for the timely recovery of prudently-incurred costs during a time of increasing costs and limited projected demand growth over the next several years. Plant Vogtle Units 3 and 4 construction and rate recovery are also major factors. Future earnings will be driven primarily by customer growth. Earnings will also depend upon maintaining and growing sales, considering, among other things, the adoption and/or penetration rates of increasingly energy-efficient technologies, increasing volumes of electronic commerce transactions, and more multi-family home construction, all of which could contribute to a net reduction in customer usage. Earnings are subject to a variety of other factors. These factors include weather, competition, new energy contracts with other utilities, energy conservation practiced by customers, the use of alternative energy sources by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in Georgia Power's service territory. Demand for electricity is primarily driven by the pace of economic growth that may be affected by changes in regional and global economic conditions, which may impact future earnings.
For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL of Georgia Power in Item 7 of the Form 10-K.
Environmental Matters
Georgia Power's operations are regulated by state and federal environmental agencies through a variety of laws and regulations governing air, water, land, and protection of other natural resources. Georgia Power maintains comprehensive environmental compliance and greenhouse gas (GHG) strategies to assess upcoming requirements and compliance costs associated with these environmental laws and regulations. The costs, including capital expenditures and operations and maintenance costs, required to comply with environmental laws and regulations and to achieve stated goals may impact future unit retirement and replacement decisions, results of operations, cash flows, and financial condition. Related costs may result from the installation of additional environmental controls, closure and monitoring of CCR facilities, unit retirements, and adding or changing fuel sources for certain existing units, as well as related upgrades to the transmission system. A major portion of these costs are expected to be recovered through existing ratemaking provisions. The ultimate impact of environmental laws and regulations and the GHG goals discussed below will depend on various factors, such as state adoption and implementation of requirements, the availability and cost of any deployed control technology, and the outcome of pending and/or future legal challenges.

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New or revised environmental laws and regulations could affect many areas of Georgia Power's operations. The impact of any such changes cannot be determined at this time. Environmental compliance costs could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Georgia Power's Environmental Compliance Cost Recovery (ECCR) tariff allows for the recovery of capital and operations and maintenance costs related to environmental controls mandated by state and federal regulations. Further, increased costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively affect results of operations, cash flows, and financial condition. Additionally, many commercial and industrial customers may also be affected by existing and future environmental requirements, which for some may have the potential to ultimately affect their demand for electricity. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters" of Georgia Power in Item 7 and Note 3 to the financial statements of Georgia Power under "Environmental Matters" in Item 8 of the Form 10-K for additional information.
Environmental Laws and Regulations
Water Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Water Quality" of Georgia Power in Item 7 of the Form 10-K for additional information regarding the effluent limitations guidelines (ELG) rule.
On May 2, 2018, the EPA updated its anticipated final rulemaking schedule for ELG from September 2020 to December 2019. The impact of any changes to the ELG rule will depend on the content of the final rule and the outcome of any legal challenges and cannot be determined at this time.
Coal Combustion Residuals
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Coal Combustion Residuals" of Georgia Power in Item 7 of the Form 10-K for additional information regarding the Disposal of Coal Combustion Residuals from Electric Utilities rule (CCR Rule).
On July 30, 2018, the EPA published certain amendments to the CCR Rule, which will be effective August 29, 2018. These amendments extend the date from April 2019 to October 31, 2020 to cease sending CCR and other waste streams to impoundments that demonstrate compliance with all except two specified criteria. These amendments also establish groundwater protection standards for four constituents that do not have established EPA maximum contaminant levels and allow a participating state director or the EPA (where the EPA is the permitting authority) to suspend groundwater monitoring requirements under certain circumstances. Specific site impacts are being evaluated by Georgia Power.
Georgia Power continues to perform engineering studies related to its plans to close the ash ponds at all of its generating plants, including one jointly owned with Gulf Power, in compliance with federal and state CCR rules. Georgia Power also continues to refine its closure strategy and cost estimates for each ash pond and is preparing permit applications as required by the State of Georgia CCR rule. While Georgia Power believes its recorded liability for ash pond closures appropriately reflects its obligations under the current closure strategies it has elected, changes to such strategies and cost estimates would likely result in additional closure costs which would increase Georgia Power's ARO liability. It is not currently possible to determine the magnitude of an increase related to a change in closure strategies nor an increase related to ongoing engineering studies for the current closure strategies, and the timing of future cash outflows are indeterminable at this time. As permit applications advance, engineering studies continue, and the timing of ash pond closures develop further on a plant-by-plant basis during the second half of 2018 and in the future, Georgia Power will record any changes as necessary to its ARO liability, which could be material. Georgia Power expects to continue to periodically update these cost estimates as necessary, which could change further as additional information becomes available. See Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information.

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Absent continued recovery of ARO costs through regulated rates, Georgia Power's results of operations, cash flows, and financial condition could be materially impacted. The ultimate outcome of these matters cannot be determined at this time.
Global Climate Issues
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues" of Georgia Power in Item 7 of the Form 10-K for additional information.
Through 2017, the Southern Company system has achieved an estimated GHG emission reduction of 36% since 2007. In April 2018, Southern Company established an intermediate goal of a 50% reduction in carbon emissions from 2007 levels by 2030 and a long-term goal of low- to no-carbon operations by 2050. To achieve these goals, the Southern Company system expects to continue growing its renewable energy portfolio, optimize technology advancements to modernize its transmission and distribution systems, increase the use of natural gas for generation, complete construction of Plant Vogtle Units 3 and 4, invest in energy efficiency, and continue research and development efforts focused on technologies to lower GHG emissions. The Southern Company system's ability to achieve these goals also will be dependent on many external factors, including supportive national energy policies, low natural gas prices, and the development, deployment, and advancement of relevant energy technologies. The ultimate outcome of this matter cannot be determined at this time.
FERC Matters
Market-Based Rate Authority
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "FERC Matters" of Georgia Power in Item 7 of the Form 10-K for additional information regarding proceedings related to the traditional electric operating companies' (including Georgia Power's) and Southern Power's 2014 and 2017 triennial market power analyses.
On May 4, 2018, the FERC issued an order terminating both proceedings, finding that the traditional electric operating companies (including Georgia Power) and Southern Power satisfy the FERC's standards for market-based rates. On May 9, 2018, the traditional electric operating companies (including Georgia Power) and Southern Power made the compliance filing required by the order. These proceedings are essentially concluded.
Open Access Transmission Tariff
On May 10, 2018, the Alabama Municipal Electric Authority and Cooperative Energy filed with the FERC a complaint against SCS and the traditional electric operating companies (including Georgia Power) claiming that the current 11.25% base ROE used in calculating the annual transmission revenue requirements of the traditional electric operating companies' (including Georgia Power's) open access transmission tariff is unjust and unreasonable as measured by the applicable FERC standards. The complaint requests that the base ROE be set no higher than 8.65% and that the FERC order refunds for the difference in revenue requirements that results from applying a just and reasonable ROE established in this proceeding upon determining the current ROE is unjust and unreasonable. On June 18, 2018, SCS and the traditional electric operating companies (including Georgia Power) filed their response challenging the adequacy of the showing presented by the complainants and offering support for the current ROE. The ultimate outcome of this matter cannot be determined at this time.
Retail Regulatory Matters
Georgia Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Georgia PSC. Georgia Power currently recovers its costs from the regulated retail business through the 2013 ARP, which includes traditional base tariff rates, Demand-Side Management tariffs, ECCREnvironmental Compliance Cost Recovery tariffs, and Municipal Franchise Fee tariffs. Georgia Power is scheduled to file a base rate case by July 1, 2019, which may continue or modify these 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.
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 "Nuclear Construction" herein and Note 36 to the financial statements in Item 8 of Georgiathe Form 10-K for additional information.
During the first quarter 2019, Mississippi Power recorded pre-tax charges to income of $2 million ($1 million after tax), 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

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under "Retail Regulatory Matters – Nuclear Construction" in Item 8the mine and gasifier-related assets, currently estimated at up to $10 million pre-tax (excluding salvage, net of dismantlement costs), may be incurred through the Form 10-K for additional information regarding the NCCR tariff. Also see MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Fuel Cost Recovery"first half of Georgia Power in Item 7 of the Form 10-K for additional information regarding fuel cost recovery.
Rate Plans
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters – Rate Plans" of Georgia Power in Item 7 of the Form 10-K for additional information regarding Georgia Power's 2013 ARP and the Georgia PSC's 2018 order related to the Tax Reform Legislation.
On April 3, 2018, the Georgia PSC approved the Tax Reform Settlement Agreement. Pursuant to the Tax Reform Settlement Agreement, to reflect the federal income tax rate reduction impact of the Tax Reform Legislation, Georgia Power will refund to customers a total of $330 million through bill credits of $131 million in October 2018, $96 million in June 2019, and $103 million in February 2020. In addition, Georgiaperiod 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 $11 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 deferring as a regulatory liability (i)currently evaluating its options regarding the revenue equivalentfinal disposition of the tax expense reduction resulting from legislation loweringCO2 pipeline, including removal of the Georgia state income tax rate from 6.00% to 5.75% in 2019 and (ii) the entire benefit of approximately $700 million in federal and state excess accumulated deferred income taxes. The amortization of these regulatory liabilitiespipeline. This evaluation is expected to be addressedcomplete later in Georgia Power's next2019. 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 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 which is scheduled to be filed by July 1, 2019. If there is notwith the Illinois Commission requesting a $230 million increase in annual base rate caserevenues. 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 2019, customers will receive $185 million in annual bill credits beginning in 2020, with any additional federal and state income tax savings deferred as a regulatory liability, until Georgia Power's next base rate case.
Tothe equity ratio from 52% to 54% to address the negative cash flow and credit metric impacts of the Tax Reform Legislation,Legislation.
On April 16, 2019, Nicor Gas entered into a stipulation agreement to resolve all related issues with the Georgia PSC also approvedStaff of the Illinois Commission, including a ROE of 9.86% and an increase in Georgia Power's retail 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 within the statutory time limit of 11 months from the filing of the rate case, after which rate adjustments will be effective.
Atlanta Gas Light is required to file a traditional base rate case no later than June 3, 2019 for rates effective January 1, 2020.
The ultimate outcome of these matters cannot be determined at this time.

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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 15 to the lower of (i) Georgia Power's actual common equity weightfinancial statements under "Southern Company Gas – Infrastructure Replacement Programs and Capital Projects" and "Southern Power," respectively, in its capital structure or (ii) 55%, until Georgia Power's next base rate case. Benefits from reduced federal income tax rates in excessItem 8 of the amounts refundedForm 10-K and Note (K) to customers will be retainedthe 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 cover the carrying costsfinancial statements under "Georgia Power – Nuclear Construction" in Item 8 of the incremental equity in 2018Form 10-K and 2019."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 32 to the financial statements of Georgiaunder "Georgia Power under "Retail Regulatory Matters – Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding the construction of Plant Vogtle Units 3 and 4, 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 the Interim Assessment Agreement with the EPC Contractorseveral transitional arrangements to allow construction to continue. The Interim Assessment Agreement expired inIn July 2017, when Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the EPC Contractor entered into the Vogtle Services Agreement. Under the Vogtle Services Agreement, 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, entered into a construction completion agreement with Bechtel, whereby Bechtel will serve asexecuted the primary contractor for the remaining construction activities for Plant Vogtle Units 3 and 4 (Bechtel Agreement). The Bechtel Agreement, is a

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cost reimbursable plus fee arrangement, whereby Bechtel is reimbursed for actual costs plus a base fee and an at-risk fee, which is subject to adjustment based on Bechtel's performance against cost and schedule targets. Each Vogtle Owner is severally (not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to Bechtel under the Bechtel Agreement. The Vogtle Owners may terminate the Bechtel Agreement at any time for their convenience, provided that the Vogtle Owners will be required to pay

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amounts related to work performed prior to the termination (including the applicable portion of the base fee), certain termination-related costs, and, at certain stages of the work, the applicable portion of the at-risk fee. Bechtel may terminate the Bechtel Agreement under certain circumstances, including certain Vogtle Owner suspensions of work, certain breaches of the Bechtel Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events. Pursuant to the Loan Guarantee Agreement between Georgia Power and the DOE, Georgia Power is required to obtain the DOE's approval of the Bechtel Agreement prior to obtaining any further advances under the Loan Guarantee Agreement.
In December 2017, the Georgia PSC approved Georgia Power's seventeenth VCM report, which included a recommendation to continue construction of Plant Vogtle Units 3 and 4, with Southern Nuclear serving as project manager and Bechtel serving as the primary construction contractor.
Cost and Schedule
In preparation for its nineteenth VCM filing, Georgia Power requested Southern Nuclear to perform a full cost reforecast for the project. Georgia Power's approximate proportionate share of the remaining estimated capital cost to complete Plant Vogtle Units 3 and 4 by the expected in-service dates of November 2021 and November 2022, respectively, is as follows:
(in billions)(in billions)
Base project capital cost forecast(a)(b)
$8.0
$8.0
Construction contingency estimate0.4
0.4
Total project capital cost forecast(a)(b)
8.4
8.4
Net investment as of June 30, 2018(b)
(4.0)
Net investment as of March 31, 2019(b)
(4.9)
Remaining estimate to complete(a)
$4.4
$3.5
(a)Excludes financing costs expected to be capitalized through AFUDC of approximately $350$325 million.
(b)Net of $1.7 billion received from Toshiba in 2017 under the Guarantee Settlement Agreement and approximately $188 million in related Customer Refunds recognized as a regulatory liability in 2017.Refunds.
Georgia Power estimates that its financing costs for construction of Plant Vogtle Units 3 and 4 will total approximately $3.2$3.1 billion, of which $1.7$1.9 billion had been incurred through June 30, 2018.March 31, 2019.
The $0.7 billion increaseIn 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 basetotal estimated project capital cost forecast reflected in the table above primarily results from changed assumptions related to the finalization of contract scopes and management responsibilities for Bechtel and over 60 subcontractors, labor productivity rates, and craft labor incentives, as well as the related levels of project management, oversight, and support, including field supervision and engineering support.
Although Georgia Power believes these incremental costs are reasonable and necessary to complete the project and the Georgia PSC's order in the seventeenth VCM proceeding specifically states that the construction of Plant Vogtle Units 3 and 4 is not subject to a cost cap, Georgia Power does not intend to seek rate recovery for these cost increases included in the current base capital cost forecast (or any related financing costs), which will be filed with the Georgia PSC in the nineteenth VCM report at the end of August 2018. In connection with future VCM filings, Georgia Power may request the Georgia PSC to evaluate costs currently included in the construction contingency estimate for rate recovery as and when they are appropriately included in the base capital cost forecast. After considering the significant level of uncertainty that exists regarding the future recoverability of costs included in the construction contingency estimate since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in these future regulatory proceedings, Georgia

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Power has recorded a total pre-tax charge to income of $1.1 billion ($0.8 billion after tax), which includes the total increase in the capital cost forecast and construction contingency estimate as of June 30, 2018.
Subsequent to the EPC Contractor bankruptcy filing, a number of subcontractors to the EPC Contractor alleged non-payment by the EPC Contractor for amounts owed for work performed on Plant Vogtle Units 3 and 4. The expected in-service dates of November 2021 for Unit 3 and November 2022 for Unit 4, as previously approved by the Georgia Power, acting for itself and as agent for the Vogtle Owners, has taken actions to remove liens filed by these subcontractors through the posting of surety bonds. Related to such liens, certain subcontractors have filed, and additional subcontractors may file, lawsuits against the EPC Contractor and the Vogtle Owners to preserve their payment rights with respect to such claims. All known amounts associated with the removal of subcontractor liens and other EPC Contractor pre-petition accounts payable have been paid or accrued as of June 30, 2018. The ultimate liability is expected to be finalized in connection with the completion of the sale of Westinghouse.PSC, remain unchanged.
As construction continues, challenges with management of contractors, subcontractors, and vendors; supervision of craft labor and related craft labor productivity, availability,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, andor components (some of which are based on new technology that is just beginningonly recently began initial operation in the global nuclear industry at this scale);, any of which may require additional labor and/or materials; or other issues could arise and change the projected schedule and estimated cost. Monthly construction production targets established as part of a strategy to maintain and build margin to the approved in-service dates will continue to increase significantly throughout 2019. To meet these increasing monthly targets, existing craft construction productivity must improve and additional craft laborers 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 resolution of Inspections, Tests, Analyses, and Acceptance CriteriaITAAC and the related approvals by the NRC, may arise, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs.

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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 (as amended, Vogtle Joint Ownership Agreements) to provide for, among other conditions, additional Vogtle Owner approval requirements. Pursuant toEffective in August 2018, the Vogtle Joint Ownership Agreements,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 must vote to continue construction if certain adverse events occur, including: (i)(as amended, and together with the bankruptcy of Toshiba; (ii) termination or rejection in bankruptcy of certain agreements, including the Vogtle Services Agreement or the Bechtel Agreement; (iii) the Georgia PSC or Georgia Power determines that any of Georgia Power's costs relating to the construction of Plant Vogtle Units 3 and 4 will not be recovered in retail rates because such costs are deemed unreasonable or imprudent; or (iv) an increase in the construction budget contained in the seventeenth VCM report of more than $1 billion or extension of the project schedule contained in the seventeenth VCM report of more than one year. In addition, pursuant toNovember 2017 amendment, the Vogtle Joint Ownership Agreements, the required approval of holders of ownership interests in Plant Vogtle Units 3 and 4 is at least (i) 90% for a change of the primary construction contractor and (ii) 67% for material amendments to the Vogtle Services Agreement or agreements with Southern Nuclear or the primary construction contractor, including the Bechtel Agreement.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

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for the Vogtle Owners is limited to removal of Georgia Power and/or Southern Nuclear as agent, except in cases of willful misconduct.
As a result of the increase in the total project capital cost forecast and Georgia Power's decision not to seek rate recovery of the increase in the base capital costs as described in "Cost and Schedule" herein,conjunction with the nineteenth VCM report, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 mustwere required to vote to continue construction. TheIn September 2018, the Vogtle Owners are expectedunanimously voted to conduct these votes incontinue construction of Plant Vogtle Units 3 and 4.
Amendments to the third quarter 2018.Vogtle Joint Ownership Agreements
IfIn connection with the holdersvote 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 least 90% ofpre-established prices, and (ii) the MEAG Term Sheet with MEAG and MEAG SPVJ to provide funding with respect to MEAG SPVJ's ownership interestsinterest in Plant Vogtle Units 3 and 4 do not voteunder certain circumstances. On January 14, 2019, Georgia Power, MEAG, and MEAG SPVJ entered into an agreement to continue construction,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 provide thatto implement the project will be cancelled, and construction will cease. In the event that fewer than 90%provisions of the Vogtle Owners voteOwner Term Sheet.
The ultimate outcome of these matters cannot be determined at this time.
Regulatory Matters
In 2009, the Georgia PSC voted to continuecertify 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 and the other Vogtle Owners will assess optionsto recover financing costs for Plant Vogtle Units 3 and 4. IfFinancing 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 March 31, 2019, Georgia Power had recovered approximately $1.9 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 cancelledprudent, 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 $75 million in 2019 and an aggregate of approximately $635 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

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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). In addition, the staff of the Georgia PSC requested, and Georgia Power agreed, to report the results of the cost and schedule validation process to the Georgia PSC (which is expected to occur by May 1, 2019) and to file its twentieth VCM report concurrently with the twenty-first VCM report by August 31, 2019.
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 March 31, 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 predicted 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.
Litigation
In January 2017, a putative securities class action complaint was unablefiled 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

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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 itin 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.
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

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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.
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 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 March 31, 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 $0.7 billion for the first three months of 2019, a decrease of $0.8 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 $2.5 billion for the first three 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 $3.4 billion for the first three 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 three months of 2019 include decreases in assets and liabilities held for sale of $4.9 billion and $3.2 billion, respectively, primarily related to the sale of Gulf Power; the recording of $1.9 billion in operating lease right-of-use assets, net of amortization and operating lease obligations related to the adoption of FASB ASC Topic 842, Leases; a decrease of $1.7 billion in notes payable related to the repayment of short-term bank debt; an increase of $1.6 billion in total stockholders' equity primarily related to the gain on the sale

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of Gulf Power; an increase of $1.4 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; a decrease of $1.2 billion in long-term debt (including amounts due within one year) resulting from net repayments of long-term debt; and an increase of $0.8 billion in total property, plant, and equipment primarily related to the traditional electric operating companies' installation of equipment to comply with environmental standards and construction of electric generation, transmission, and distribution facilities. See Notes (F), (K), and (L) to the Condensed Financial Statements herein for additional information.
At the end of the first quarter 2019, the market price of Southern Company's common stock was $51.68 per share (based on the closing price as reported on the New York Stock Exchange) and the book value was $25.41 per share, representing a market-to-book ratio of 203%, compared to $43.92, $23.91, and 184%, respectively, at the end of 2018. Southern Company's common stock dividend for the first quarter 2019 was $0.60 per share compared to $0.58 per share in the first 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 $2.3 billion will be required through March 31, 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, increased costs, or inconsistent quality of equipment, materials, and labor; contractor or supplier delay; non-performance under construction, operating, or other agreements; operational readiness, including specialized operator training and required site safety programs; engineering or design problems; design and other licensing-based compliance matters, including the timely resolution of ITAAC and the related approvals by the NRC; challenges with start-up activities, including major equipment failure and system integration; 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 PowerNuclear Construction" herein for information regarding Plant Vogtle Units 3 and 4 and additional factors that may impact construction expenditures.

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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 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 sales. 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 sales of Plants Mankato and Nacogdoches.
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 project,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 March 31, 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 PowerNuclear Construction" herein for additional information regarding Plant Vogtle Units 3 and 4.
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 March 31, 2019, Southern Company's current liabilities exceeded current assets by $1.2 billion, primarily due to long-term debt that is due within one year of $2.3 billion (including approximately $1.0 billion at Georgia Power, $0.3 billion at Mississippi Power, $0.6 billion at Southern Power, and $0.4 billion at Southern Company Gas) and notes payable of $1.3 billion (including approximately $0.5 billion at the parent company, $0.3 billion at Georgia Power, $0.1 billion at Southern Power, and $0.4 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

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operating companies, Southern Power, and Southern Company Gas, equity contributions and/or loans from Southern Company to meet their short-term capital needs.
At March 31, 2019, Southern Company and its subsidiaries had approximately $1.4 billion of cash and cash equivalents. Committed credit arrangements with banks at March 31, 2019 were as follows:
 Expires  
Company201920202022 Total 
Unused(d)
 (in millions)
Southern Company(a)
$
$
$2,000
 $2,000
 $1,999
Alabama Power33
500
800
 1,333
 1,333
Georgia Power

1,750
 1,750
 1,736
Mississippi Power100


 100
 100
Southern Power(b)


750
 750
 741
Southern Company Gas(c)


1,900
 1,900
 1,895
Other30


 30
 30
Southern Company Consolidated$163
$500
$7,200
 $7,863
 $7,834
(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 $24 million was unused at March 31, 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 $1.4 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.
(d)Amounts used are for letters of credit.
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, Southern Power Company, 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 March 31, 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 March 31, 2019 was approximately $1.4 billion. In addition, at March 31, 2019, the traditional electric operating companies had approximately $432 million of revenue bonds outstanding that are required to be remarketed within the next 12 months. Subsequent to March 31, 2019, Georgia Power purchased and held approximately $115 million of outstanding pollution control revenue bonds required to be remarketed.

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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.
Details of short-term borrowings were as follows:
  
Short-term Debt at
March 31, 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 $1,151
 2.9% $1,248
 2.9% $2,293
Short-term bank debt 100
 3.1% 208
 3.2% 1,850
Total $1,251
 2.9% $1,456
 2.9%  
(*)Average and maximum amounts are based upon daily balances during the three-month period ended March 31, 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 March 31, 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 March 31, 2019 were as follows:
Credit RatingsMaximum Potential
Collateral
Requirements
 (in millions)
At BBB and/or Baa2$30
At BBB- and/or Baa3$433
At BB+ and/or Ba1(*)
$1,988
(*)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 for

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

additional information related to state PSC or other regulatory agency actions related to the Tax Reform Legislation, including approvals of capital structure adjustments for Alabama Power, Georgia Power, and Atlanta Gas Light by their respective state PSCs and a similar request by Nicor Gas currently pending Illinois Commission approval, which are expected to help mitigate the potential adverse impacts to certain of their credit metrics.
Financing Activities
During the first three months of 2019, Southern Company issued approximately 6.5 million shares of common stock primarily through employee equity compensation plans and received proceeds of approximately $224 million.
The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first three months of 2019:
CompanySenior 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 Power200
 
 
 
 
Georgia Power
 343
 108
 835
 2
Mississippi Power
 43
 
 
 
Other
 
 
 
 19
Southern Company Consolidated$2,300
 $386
 $108
 $835
 $21
(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.

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Subsequent to March 31, 2019, Georgia Power purchased and held the following pollution control revenue bonds, which may be reoffered to the public at a later date:
$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 addition to any financings that may be necessary to meet capital requirements and contractual obligations, Southern Company and its subsidiaries plan to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.

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PART I
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
During the three months ended March 31, 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 first 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 March 31,
 2019 2018
 (in millions)
Operating Revenues:   
Retail revenues$1,213
 $1,285
Wholesale revenues, non-affiliates61
 74
Wholesale revenues, affiliates60
 51
Other revenues74
 63
Total operating revenues1,408
 1,473
Operating Expenses:   
Fuel301
 326
Purchased power, non-affiliates37
 64
Purchased power, affiliates21
 37
Other operations and maintenance409
 387
Depreciation and amortization199
 189
Taxes other than income taxes103
 98
Total operating expenses1,070
 1,101
Operating Income338
 372
Other Income and (Expense):   
Allowance for equity funds used during construction14
 13
Interest expense, net of amounts capitalized(83) (79)
Other income (expense), net14
 5
Total other income and (expense)(55) (61)
Earnings Before Income Taxes283
 311
Income taxes62
 82
Net Income221
 229
Dividends on Preferred Stock4
 4
Net Income After Dividends on Preferred Stock$217
 $225

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
 For the Three Months
Ended March 31,
 2019 2018
 (in millions)
Net Income$221
 $229
Other comprehensive income (loss):   
Qualifying hedges:   
Reclassification adjustment for amounts included in net income,
net of tax of $- and $1, respectively
1
 1
Total other comprehensive income (loss)1
 1
Comprehensive Income$222
 $230
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 Three Months
Ended March 31,
 2019 2018
 (in millions)
Operating Activities:   
Net income$221
 $229
Adjustments to reconcile net income to net cash provided from operating activities —   
Depreciation and amortization, total244
 228
Deferred income taxes
 32
Other, net(24) (21)
Changes in certain current assets and liabilities —   
-Receivables105
 (1)
-Prepayments(78) (82)
-Materials and supplies(4) (27)
-Other current assets19
 19
-Accounts payable(286) (216)
-Accrued taxes80
 57
-Accrued compensation(122) (108)
-Other current liabilities(9) 45
Net cash provided from operating activities146
 155
Investing Activities:   
Property additions(390) (490)
Nuclear decommissioning trust fund purchases(68) (50)
Nuclear decommissioning trust fund sales68
 51
Cost of removal, net of salvage(16) (19)
Change in construction payables(95) (50)
Other investing activities(10) (6)
Net cash used for investing activities(511) (564)
Financing Activities:   
Increase in notes payable, net
 245
Proceeds — Capital contributions from parent company1,232
 484
Redemptions — Senior notes(200) 
Payment of common stock dividends(211) (202)
Other financing activities(10) (9)
Net cash provided from financing activities811
 518
Net Change in Cash, Cash Equivalents, and Restricted Cash446
 109
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period313
 544
Cash, Cash Equivalents, and Restricted Cash at End of Period$759
 $653
Supplemental Cash Flow Information:   
Cash paid during the period for —   
Interest (net of $5 and $5 capitalized for 2019 and 2018, respectively)$89
 $84
Income taxes, net
 9
Noncash transactions — Accrued property additions at end of period176
 195
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 March 31, 2019 At December 31, 2018
  (in millions)
Current Assets:    
Cash and cash equivalents $759
 $313
Receivables —    
Customer accounts receivable 382
 403
Unbilled revenues 126
 150
Affiliated 45
 94
Other accounts and notes receivable 58
 51
Accumulated provision for uncollectible accounts (10) (10)
Fossil fuel stock 120
 141
Materials and supplies 558
 546
Prepaid expenses 113
 66
Other regulatory assets 125
 137
Other current assets 21
 18
Total current assets 2,297
 1,909
Property, Plant, and Equipment:    
In service 28,810
 30,402
Less: Accumulated provision for depreciation 9,447
 9,988
Plant in service, net of depreciation 19,363
 20,414
Other utility plant, net 1,315
 
Nuclear fuel, at amortized cost 320
 324
Construction work in progress 1,023
 1,113
Total property, plant, and equipment 22,021
 21,851
Other Property and Investments:    
Equity investments in unconsolidated subsidiaries 64
 65
Nuclear decommissioning trusts, at fair value 933
 847
Miscellaneous property and investments 129
 127
Total other property and investments 1,126
 1,039
Deferred Charges and Other Assets:    
Operating lease right-of-use assets, net of amortization 160
 
Deferred charges related to income taxes 239
 240
Deferred under recovered regulatory clause revenues 21
 116
Other regulatory assets, deferred 1,350
 1,386
Other deferred charges and assets 193
 189
Total deferred charges and other assets 1,963
 1,931
Total Assets $27,407
 $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 March 31, 2019 At December 31, 2018
  (in millions)
Current Liabilities:    
Securities due within one year $1
 $201
Accounts payable —    
Affiliated 262
 364
Other 346
 614
Customer deposits 97
 96
Accrued taxes 97
 44
Accrued interest 77
 89
Accrued compensation 102
 227
Asset retirement obligations 163
 163
Other current liabilities 97
 161
Total current liabilities 1,242
 1,959
Long-term Debt 7,924
 7,923
Deferred Credits and Other Liabilities:    
Accumulated deferred income taxes 2,971
 2,962
Deferred credits related to income taxes 2,015
 2,027
Accumulated deferred ITCs 105
 106
Employee benefit obligations 302
 314
Operating lease obligations 147
 
Asset retirement obligations, deferred 3,064
 3,047
Other cost of removal obligations 489
 497
Other regulatory liabilities 107
 69
Other deferred credits and liabilities 30
 58
Total deferred credits and other liabilities 9,230
 9,080
Total Liabilities 18,396
 18,962
Redeemable Preferred Stock 291
 291
Common Stockholder's Equity (See accompanying statements)
 8,720
 7,477
Total Liabilities and Stockholder's Equity $27,407
 $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, 201731
 $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, 201831
 $1,222
 $3,474
 $2,670
 $(31) $7,335
            
Balance at December 31, 201831
 $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, 201931
 $1,222
 $4,744
 $2,781
 $(27) $8,720
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



FIRST QUARTER 2019 vs. FIRST QUARTER 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
First Quarter 2019 vs. First Quarter 2018
(change in millions)
(% change)
$(8) (3.6)
Alabama Power's net income after dividends on preferred stock for the first quarter 2019 was $217 million compared to $225 million for the corresponding period in 2018. This decrease was primarily related to a decrease in retail revenues associated with milder weather and lower customer usage and an increase in non-fuel operations and maintenance expenses. These decreases to income were partially offset by an increase in retail revenues under Rate CNP Compliance associated with increases in average net investments and a decrease in income tax expense associated with the application in 2018 of the accounting order approved by the Alabama PSC in May 2018 related to the Tax Reform Legislation (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.
Retail Revenues
First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change)
$(72) (5.6)
In the first quarter 2019, retail revenues were $1.21 billion compared to $1.29 billion for the corresponding period in 2018.

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ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



Details of the changes in retail revenues were as follows:
 First Quarter 2019
 (in millions)
(% change)
Retail – prior year$1,285
  
Estimated change resulting from –   
Rates and pricing34
 2.6
Sales decline(17) (1.3)
Weather(25) (1.9)
Fuel and other cost recovery(64) (5.0)
Retail – current year$1,213
 (5.6)%
Revenues associated with changes in rates and pricing increased in the first quarter 2019 when compared to the corresponding period in 2018 primarily due to increased revenues under Rate CNP Compliance associated with increases in average net investments. See Note 2 to the financial statements under "Alabama Power" in Item 8 of the Form 10-K for additional information.
Revenues attributable to changes in sales decreased in the first quarter 2019 when compared to the corresponding period in 2018. Weather-adjusted commercial KWH sales decreased 3.5% in the first quarter 2019 and weather-adjusted residential KWH sales decreased 2.3% in the first quarter 2019 when compared to the corresponding period in 2018 primarily due to lower customer usage resulting from customer initiatives in energy savings for commercial customers and lower usage due to more energy-efficient residential appliances. Industrial KWH sales decreased 3.0% in the first quarter 2019 when compared to the corresponding period in 2018 as a result of a decrease in demand resulting from changes in production levels primarily in the primary metals, chemicals, and paper sectors, partially offset by increased demand in the pipeline sector.
Revenues resulting from changes in weather decreased in the first quarter 2019 due to milder weather. In the first quarter 2019, the resulting decreases were 3.3% and 1.7% for residential and commercial sales revenues, respectively.
Fuel and other cost recovery revenues decreased in the first quarter 2019 when compared to the corresponding period in 2018 primarily due to a decrease in generation.
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.
Wholesale Revenues Non-Affiliates
First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change)
$(13) (17.6)
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.

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ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



In the first quarter 2019, wholesale revenues from sales to non-affiliates were $61 million compared to $74 million for the corresponding period in 2018. The decrease was primarily due to a 10.1% decrease in the price of energy due to lower natural gas prices and a 9.4% decrease in KWH sales as a result of lower demand in the first quarter 2019 compared to the corresponding period in 2018.
Wholesale Revenues Affiliates
First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change)
$9 17.6
Wholesale revenues from sales to affiliated companies will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since 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 first quarter 2019, wholesale revenues from sales to affiliates were $60 million compared to $51 million for the corresponding period in 2018. The increase was primarily due to a 33.4% increase in KWH sales partially offset by a 12.6% decrease in the price of energy due to increased hydro generation in the first quarter 2019 as compared to the corresponding period in 2018.
Other Revenues
First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change)
$11 17.5
In the first quarter 2019, other revenues were $74 million compared to $63 million for the corresponding period in 2018. This increase was primarily due to an increase in OATT revenues and opportunity sales of natural gas.
Fuel and Purchased Power Expenses
 First Quarter 2019 vs. First Quarter 2018
 (change in millions) (% change)
Fuel$(25) (7.7)
Purchased power – non-affiliates(27) (42.2)
Purchased power – affiliates(16) (43.2)
Total fuel and purchased power expenses$(68)  
In the first quarter 2019, fuel and purchased power expenses were $359 million compared to $427 million for the corresponding period in 2018. The decrease was primarily due to a $53 million decrease related to the volume of KWHs generated (excluding hydro) and purchased and a $14 million decrease in the average cost of purchased power.
Fuel and purchased power energy transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through Alabama Power's energy cost recovery clause. See Note 2 to the financial statements under "Alabama Power – Rate ECR" in Item 8 of the Form 10-K for additional information.

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ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



Details of Alabama Power's generation and purchased power were as follows:
 First Quarter 2019
First Quarter 2018
Total generation (in billions of KWHs)
16 16
Total purchased power (in billions of KWHs)
1 1
Sources of generation (percent) —
   
Coal43 50
Nuclear23 23
Gas19 18
Hydro15 9
Cost of fuel, generated (in cents per net KWH) 
   
Coal2.78 2.69
Nuclear0.78 0.75
Gas2.57 2.87
Average cost of fuel, generated (in cents per net KWH)(a)
2.19 2.23
Average cost of purchased power (in cents per net KWH)(b)
5.75 7.10
(a)KWHs generated by hydro are excluded from the average cost of fuel, generated.
(b)Average cost of purchased power includes fuel, energy, and transmission purchased by Alabama Power for tolling agreements where power is generated by the provider.
Fuel
In the first quarter 2019, fuel expense was $301 million compared to $326 million for the corresponding period in 2018. The decrease was primarily due to a 79.7% increase in the volume of KWHs generated by hydro, a 12.7% decrease in the volume of KWHs generated by coal, and a 10.5% decrease in the average cost of natural gas per KWH generated, which excludes fuel associated with tolling agreements. The decrease was partially offset by a 4.6% increase in the volume of KWHs generated by natural gas and a 3.4% increase in the average cost of coal per KWH generated.
Purchased Power – Non-Affiliates
In the first quarter 2019, purchased power expense from non-affiliates was $37 million compared to $64 million for the corresponding period in 2018. The decrease was primarily related to a 28.3% decrease in the average cost of purchased power per KWH due to lower natural gas prices and a 19.7% 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 first quarter 2019, purchased power expense from affiliates was $21 million compared to $37 million for the corresponding period in 2018. The decrease was primarily related to a 48.6% decrease in the amount of energy purchased due to increased hydro generation, partially offset by an 11.4% increase in the average cost of purchased power per KWH as a result of firm transportation costs.
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.

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Other Operations and Maintenance Expenses
First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change)
$22 5.7
In the first quarter 2019, other operations and maintenance expenses were $409 million compared to $387 million for the corresponding period in 2018. This increase was primarily due to increases of $8 million in environmental expenses, $6 million in certain compensation and benefit expenses, and $4 million in nuclear generation expenses primarily due to plant improvement projects.
Depreciation and Amortization
First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change)
$10 5.3
In the first quarter 2019, depreciation and amortization was $199 million compared to $189 million for the corresponding period in 2018. This increase was primarily due to additional plant in service associated with compliance-related steam, distribution, and transmission.
Other Income (Expense), Net
First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change)
$9 180.0
In the first quarter 2019, other income (expense), net was $14 million compared to $5 million for the corresponding period in 2018. This increase was primarily due to an increase in interest income from temporary cash investments and additional sales of non-utility property in 2019.
Income Taxes
First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change)
$(20) (24.4)
In the first quarter 2019, income taxes were $62 million compared to $82 million for the corresponding period in 2018. This decrease was primarily due to lower pre-tax earnings in the first 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

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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. The costs, including capital expenditures, operations and maintenance costs, and costs reflected in ARO liabilities, required to comply with environmental laws and regulations and to achieve stated goals may impact future electric generating unit retirement and replacement decisions, results of operations, cash flow,flows, and/or financial condition. 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. A major portion of these costs is expected to be recovered through existing ratemaking provisions. 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 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 wouldcondition. Additionally, many commercial and industrial customers may also be materially impacted.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.
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 March 25, 2019, the Alabama Municipal Electric Authority and Cooperative Energy and SCS and the traditional electric operating companies (including Alabama Power) filed a formal settlement agreement with the FERC agreeing to a 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 ultimate outcome of this matter cannot be determined at this time.time; however, if approved by the FERC as filed, the OATT settlement would not have a material impact on the financial statements of Alabama Power.
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

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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
In connection with management's decision to retire Plant Gorgas, in February 2019, Alabama Power reclassified approximately $1.3 billion for Plant Gorgas Unit 10 from plant in service, net of depreciation to other utility plant, net and continued to depreciate the asset according to the original depreciation rates. On April 15, 2019, Alabama Power retired Plant Gorgas Units 8, 9, and 10 and reclassified approximately $740 million of the remaining net investment costs of the units to a regulatory asset to be recovered over the units' remaining useful lives as established prior to the decision to retire. Additionally, approximately $700 million of net capitalized asset retirement costs will be reclassified to a regulatory asset and recovered in accordance with accounting guidance provided by the Alabama PSC. 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 predicted 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.
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.
Recently Issued Accounting Standards
See Note (A) to the Condensed Financial Statements herein for information regarding Alabama 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 Alabama Power in Item 7 of the Form 10-K for additional information. Alabama Power's financial condition remained stable at March 31, 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 $146 million for the first three months of 2019, a decrease of $9 million as compared to the first three months of 2018. The decrease in net cash provided from operating activities was primarily due to timing of vendor payments and other current liabilities, partially offset by increased fuel cost recovery. Net cash used for investing activities totaled $511 million for the first three months of 2019 primarily related to additional capital expenditures for distribution, environmental, and transmission assets. Net cash provided from financing activities totaled $811 million for the first three 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 three months of 2019 include increases of $1.2 billion in total common stockholder's equity, primarily due to a $1.225 billion capital contribution from Southern Company, and $446 million in cash and cash equivalents. Other significant changes include decreases of $268 million in other accounts payable primarily due to the timing of vendor payments and $200 million in securities due within one year due to the maturity of long-term debt.
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 March 31, 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 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

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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 March 31, 2019, Alabama Power had approximately $759 million of cash and cash equivalents. Committed credit arrangements with banks at March 31, 2019 were as follows:
Expires    
2019 2020 2022 Total Unused
(in millions)
$33
 $500
 $800
 $1,333
 $1,333
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 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 March 31, 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 March 31, 2019. At March 31, 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.
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$32
 2.7% $185
(*)Average and maximum amounts are based upon daily balances during the three-month period ended March 31, 2019. No short-term debt was outstanding at March 31, 2019.

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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 March 31, 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 March 31, 2019, the maximum potential collateral requirements at a rating below BBB- and/or Baa3 totaled approximately $354 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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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
In connection with management's decision to retire Plant Gorgas, in February 2019, Alabama Power reclassified approximately $1.3 billion for Plant Gorgas Unit 10 from plant in service, net of depreciation to other utility plant, net and continued to depreciate the asset according to the original depreciation rates. On April 15, 2019, Alabama Power retired Plant Gorgas Units 8, 9, and 10 and reclassified approximately $740 million of the remaining net investment costs of the units to a regulatory asset to be recovered over the units' remaining useful lives as established prior to the decision to retire. Additionally, approximately $700 million of net capitalized asset retirement costs will be reclassified to a regulatory asset and recovered in accordance with accounting guidance provided by the Alabama PSC. 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 tariffs, and Municipal Franchise Fee tariffs. Georgia Power is scheduled to file a base rate case by July 1, 2019, which may continue or modify these 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.
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 first quarter 2019, Mississippi Power recorded pre-tax charges to income of $2 million ($1 million after tax), 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

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the mine and gasifier-related assets, currently estimated at up to $10 million pre-tax (excluding salvage, net of dismantlement costs), 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 $11 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 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 within the statutory time limit of 11 months from the filing of the rate case, after which rate adjustments will be effective.
Atlanta Gas Light is required to file a traditional base rate case no later than June 3, 2019 for rates effective January 1, 2020.
The ultimate outcome of these matters cannot be determined at this time.

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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 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

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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.
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 estimate0.4
Total project capital cost forecast(a)(b)
8.4
Net investment as of March 31, 2019(b)
(4.9)
Remaining estimate to complete(a)
$3.5
(a)Excludes financing costs expected to be capitalized through AFUDC of approximately $325 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 $1.9 billion had been incurred through March 31, 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 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.
As construction continues, 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), any of which may require additional labor and/or materials; or other issues could arise and change the projected schedule and estimated cost. Monthly construction production targets established as part of a strategy to maintain and build margin to the approved in-service dates will continue to increase significantly throughout 2019. To meet these increasing monthly targets, existing craft construction productivity must improve and additional craft laborers 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 resolution of ITAAC and the related approvals by the NRC, may arise, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs.

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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) 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. As of June 30, 2018,At March 31, 2019, Georgia Power had recovered approximately $1.7$1.9 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) certain recommendations made by Georgia Power in thePower's seventeenth VCM report and modifyingmodified 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

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(provided (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 unitUnit is commercially operational. The ROE reductions negatively impacted earnings by approximately $25$100 million in 20172018 and are estimated to have negative earnings impacts of approximately $100$75 million in 20182019 and an aggregate of $585approximately $635 million from 20192020 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.
OnIn February 12, 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. OnIn March 8, 2018, Georgia Watch filed a similar appeal to the Fulton County Superior Court for judicial review of the Georgia PSC's final decision and denial of Georgia Watch's motion for reconsideration. 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 two appeals haveappeal has no merit; however, an adverse outcome in eitherthe appeal combined with subsequent adverse action by the Georgia PSC could have a material impact on Georgia Power'sSouthern Company's results of operations, financial condition, and liquidity.
The Georgia PSC has approved seventeen VCM reports covering the periods through June 30, 2017, including total construction capital costs incurred through that date of $4.4 billion. OnIn August 21, 2018, the Georgia PSC is scheduled to vote on Georgia Power's eighteenth VCM report, which requested approval of $448 million of construction capital costs (excluding the $1.7 billion received from Toshiba under the Guarantee Settlement Agreement and the $188 million in Customer Refunds recognized as a regulatory liability) incurred from July 1, 2017 through December 31, 2017.
On August 31, 2018, Georgia Power will filefiled its nineteenth VCM report with the Georgia PSC, which will reflect the revised capital cost forecast discussed previously and requestrequested 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). In addition, the staff of the Georgia PSC requested, and Georgia Power agreed, to report the results of the cost and schedule validation process to the Georgia PSC (which is expected to occur by May 1, 2019) and to file its twentieth VCM report concurrently with the twenty-first VCM report by August 31, 2019.
The ultimate outcome of these matters cannot be determined at this time.
See RISK FACTORS of Georgia PowerSouthern Company in Item 1A herein and of the Form 10-K for a discussion of certain risks associated with the licensing, construction, and operation of nuclear generating units, including potential impacts that could result from a major incident at a nuclear facility anywhere in the world.
DOE Financing
As of June 30, 2018,At March 31, 2019, Georgia Power had borrowed $2.6$3.46 billion related to Plant Vogtle Units 3 and 4 costs as provided through the Amended and Restated Loan Guarantee Agreement and arelated multi-advance credit facilityfacilities among Georgia Power, the DOE, and the FFB, which providesprovide for borrowings of up to $3.46approximately $5.130 billion, subject to the satisfaction of certain conditions. In September 2017, the DOE issued a conditional commitment to Georgia Power for up to approximately $1.67 billion in additional guaranteed loans under the Loan Guarantee Agreement. In June 2018, the DOE approved a request by Georgia Power to extend the conditional commitment to September 30, 2018. Any further extension must be approved by the DOE. Final approval and issuance of these additional loan guarantees by the DOE cannot be assured and are subject to the negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions, including the Vogtle Owners' votes to continue construction. See Note 68 to the financial statements of Georgia Power under "DOE"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, (includingand 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 predicted 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, decision notarising 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.
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

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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.
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

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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.
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 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 March 31, 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 $0.7 billion for the first three months of 2019, a decrease of $0.8 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 $2.5 billion for the first three 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 $3.4 billion for the first three 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 three months of 2019 include decreases in assets and liabilities held for sale of $4.9 billion and $3.2 billion, respectively, primarily related to the sale of Gulf Power; the recording of $1.9 billion in operating lease right-of-use assets, net of amortization and operating lease obligations related to the adoption of FASB ASC Topic 842, Leases; a decrease of $1.7 billion in notes payable related to the repayment of short-term bank debt; an increase of $1.6 billion in total stockholders' equity primarily related to the gain on the sale

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of Gulf Power; an increase of $1.4 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; a decrease of $1.2 billion in long-term debt (including amounts due within one year) resulting from net repayments of long-term debt; and an increase of $0.8 billion in total property, plant, and equipment primarily related to the traditional electric operating companies' installation of equipment to comply with environmental standards and construction of electric generation, transmission, and distribution facilities. See Notes (F), (K), and (L) to the Condensed Financial Statements herein for additional information.
At the end of the first quarter 2019, the market price of Southern Company's common stock was $51.68 per share (based on the closing price as reported on the New York Stock Exchange) and the book value was $25.41 per share, representing a market-to-book ratio of 203%, compared to $43.92, $23.91, and 184%, respectively, at the end of 2018. Southern Company's common stock dividend for the first quarter 2019 was $0.60 per share compared to $0.58 per share in the first 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 $2.3 billion will be required through March 31, 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, increased costs, or inconsistent quality of equipment, materials, and labor; contractor or supplier delay; non-performance under construction, operating, or other agreements; operational readiness, including specialized operator training and required site safety programs; engineering or design problems; design and other licensing-based compliance matters, including the timely resolution of ITAAC and the related approvals by the NRC; challenges with start-up activities, including major equipment failure and system integration; 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 PowerNuclear Construction" herein for information regarding Plant Vogtle Units 3 and 4 and additional factors that may impact construction expenditures.

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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 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 sales. 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 sales of Plants Mankato and Nacogdoches.
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),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 March 31, 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 PowerNuclear Construction" herein for additional information regarding Plant Vogtle Units 3 and 4.
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 March 31, 2019, Southern Company's current liabilities exceeded current assets by $1.2 billion, primarily due to long-term debt that is due within one year of $2.3 billion (including approximately $1.0 billion at Georgia Power, $0.3 billion at Mississippi Power, $0.6 billion at Southern Power, and $0.4 billion at Southern Company Gas) and notes payable of $1.3 billion (including approximately $0.5 billion at the parent company, $0.3 billion at Georgia Power, $0.1 billion at Southern Power, and $0.4 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

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operating companies, Southern Power, and Southern Company Gas, equity contributions and/or loans from Southern Company to meet their short-term capital needs.
At March 31, 2019, Southern Company and its subsidiaries had approximately $1.4 billion of cash and cash equivalents. Committed credit arrangements with banks at March 31, 2019 were as follows:
 Expires  
Company201920202022 Total 
Unused(d)
 (in millions)
Southern Company(a)
$
$
$2,000
 $2,000
 $1,999
Alabama Power33
500
800
 1,333
 1,333
Georgia Power

1,750
 1,750
 1,736
Mississippi Power100


 100
 100
Southern Power(b)


750
 750
 741
Southern Company Gas(c)


1,900
 1,900
 1,895
Other30


 30
 30
Southern Company Consolidated$163
$500
$7,200
 $7,863
 $7,834
(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 $24 million was unused at March 31, 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 $1.4 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.
(d)Amounts used are for letters of credit.
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, Southern Power Company, 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 March 31, 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 March 31, 2019 was approximately $1.4 billion. In addition, at March 31, 2019, the traditional electric operating companies had approximately $432 million of revenue bonds outstanding that are required to be remarketed within the next 12 months. Subsequent to March 31, 2019, Georgia Power purchased and held approximately $115 million of outstanding pollution control revenue bonds required to be remarketed.

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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.
Details of short-term borrowings were as follows:
  
Short-term Debt at
March 31, 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 $1,151
 2.9% $1,248
 2.9% $2,293
Short-term bank debt 100
 3.1% 208
 3.2% 1,850
Total $1,251
 2.9% $1,456
 2.9%  
(*)Average and maximum amounts are based upon daily balances during the three-month period ended March 31, 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 March 31, 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 March 31, 2019 were as follows:
Credit RatingsMaximum Potential
Collateral
Requirements
 (in millions)
At BBB and/or Baa2$30
At BBB- and/or Baa3$433
At BB+ and/or Ba1(*)
$1,988
(*)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 for

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

additional information related to state PSC or other regulatory agency actions related to the Tax Reform Legislation, including approvals of capital structure adjustments for Alabama Power, Georgia Power, and Atlanta Gas Light by their respective state PSCs and a similar request by Nicor Gas currently pending Illinois Commission approval, which are expected to help mitigate the potential adverse impacts to certain of their credit metrics.
Financing Activities
During the first three months of 2019, Southern Company issued approximately 6.5 million shares of common stock primarily through employee equity compensation plans and received proceeds of approximately $224 million.
The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first three months of 2019:
CompanySenior 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 Power200
 
 
 
 
Georgia Power
 343
 108
 835
 2
Mississippi Power
 43
 
 
 
Other
 
 
 
 19
Southern Company Consolidated$2,300
 $386
 $108
 $835
 $21
(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.

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SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Subsequent to March 31, 2019, Georgia Power purchased and held the following pollution control revenue bonds, which may be reoffered to the public at a later date:
$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 addition to any financings that may be necessary to meet capital requirements and contractual obligations, Southern Company and its subsidiaries plan to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.

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PART I
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
During the three months ended March 31, 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 first 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 March 31,
 2019 2018
 (in millions)
Operating Revenues:   
Retail revenues$1,213
 $1,285
Wholesale revenues, non-affiliates61
 74
Wholesale revenues, affiliates60
 51
Other revenues74
 63
Total operating revenues1,408
 1,473
Operating Expenses:   
Fuel301
 326
Purchased power, non-affiliates37
 64
Purchased power, affiliates21
 37
Other operations and maintenance409
 387
Depreciation and amortization199
 189
Taxes other than income taxes103
 98
Total operating expenses1,070
 1,101
Operating Income338
 372
Other Income and (Expense):   
Allowance for equity funds used during construction14
 13
Interest expense, net of amounts capitalized(83) (79)
Other income (expense), net14
 5
Total other income and (expense)(55) (61)
Earnings Before Income Taxes283
 311
Income taxes62
 82
Net Income221
 229
Dividends on Preferred Stock4
 4
Net Income After Dividends on Preferred Stock$217
 $225

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
 For the Three Months
Ended March 31,
 2019 2018
 (in millions)
Net Income$221
 $229
Other comprehensive income (loss):   
Qualifying hedges:   
Reclassification adjustment for amounts included in net income,
net of tax of $- and $1, respectively
1
 1
Total other comprehensive income (loss)1
 1
Comprehensive Income$222
 $230
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 Three Months
Ended March 31,
 2019 2018
 (in millions)
Operating Activities:   
Net income$221
 $229
Adjustments to reconcile net income to net cash provided from operating activities —   
Depreciation and amortization, total244
 228
Deferred income taxes
 32
Other, net(24) (21)
Changes in certain current assets and liabilities —   
-Receivables105
 (1)
-Prepayments(78) (82)
-Materials and supplies(4) (27)
-Other current assets19
 19
-Accounts payable(286) (216)
-Accrued taxes80
 57
-Accrued compensation(122) (108)
-Other current liabilities(9) 45
Net cash provided from operating activities146
 155
Investing Activities:   
Property additions(390) (490)
Nuclear decommissioning trust fund purchases(68) (50)
Nuclear decommissioning trust fund sales68
 51
Cost of removal, net of salvage(16) (19)
Change in construction payables(95) (50)
Other investing activities(10) (6)
Net cash used for investing activities(511) (564)
Financing Activities:   
Increase in notes payable, net
 245
Proceeds — Capital contributions from parent company1,232
 484
Redemptions — Senior notes(200) 
Payment of common stock dividends(211) (202)
Other financing activities(10) (9)
Net cash provided from financing activities811
 518
Net Change in Cash, Cash Equivalents, and Restricted Cash446
 109
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period313
 544
Cash, Cash Equivalents, and Restricted Cash at End of Period$759
 $653
Supplemental Cash Flow Information:   
Cash paid during the period for —   
Interest (net of $5 and $5 capitalized for 2019 and 2018, respectively)$89
 $84
Income taxes, net
 9
Noncash transactions — Accrued property additions at end of period176
 195
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 March 31, 2019 At December 31, 2018
  (in millions)
Current Assets:    
Cash and cash equivalents $759
 $313
Receivables —    
Customer accounts receivable 382
 403
Unbilled revenues 126
 150
Affiliated 45
 94
Other accounts and notes receivable 58
 51
Accumulated provision for uncollectible accounts (10) (10)
Fossil fuel stock 120
 141
Materials and supplies 558
 546
Prepaid expenses 113
 66
Other regulatory assets 125
 137
Other current assets 21
 18
Total current assets 2,297
 1,909
Property, Plant, and Equipment:    
In service 28,810
 30,402
Less: Accumulated provision for depreciation 9,447
 9,988
Plant in service, net of depreciation 19,363
 20,414
Other utility plant, net 1,315
 
Nuclear fuel, at amortized cost 320
 324
Construction work in progress 1,023
 1,113
Total property, plant, and equipment 22,021
 21,851
Other Property and Investments:    
Equity investments in unconsolidated subsidiaries 64
 65
Nuclear decommissioning trusts, at fair value 933
 847
Miscellaneous property and investments 129
 127
Total other property and investments 1,126
 1,039
Deferred Charges and Other Assets:    
Operating lease right-of-use assets, net of amortization 160
 
Deferred charges related to income taxes 239
 240
Deferred under recovered regulatory clause revenues 21
 116
Other regulatory assets, deferred 1,350
 1,386
Other deferred charges and assets 193
 189
Total deferred charges and other assets 1,963
 1,931
Total Assets $27,407
 $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 March 31, 2019 At December 31, 2018
  (in millions)
Current Liabilities:    
Securities due within one year $1
 $201
Accounts payable —    
Affiliated 262
 364
Other 346
 614
Customer deposits 97
 96
Accrued taxes 97
 44
Accrued interest 77
 89
Accrued compensation 102
 227
Asset retirement obligations 163
 163
Other current liabilities 97
 161
Total current liabilities 1,242
 1,959
Long-term Debt 7,924
 7,923
Deferred Credits and Other Liabilities:    
Accumulated deferred income taxes 2,971
 2,962
Deferred credits related to income taxes 2,015
 2,027
Accumulated deferred ITCs 105
 106
Employee benefit obligations 302
 314
Operating lease obligations 147
 
Asset retirement obligations, deferred 3,064
 3,047
Other cost of removal obligations 489
 497
Other regulatory liabilities 107
 69
Other deferred credits and liabilities 30
 58
Total deferred credits and other liabilities 9,230
 9,080
Total Liabilities 18,396
 18,962
Redeemable Preferred Stock 291
 291
Common Stockholder's Equity (See accompanying statements)
 8,720
 7,477
Total Liabilities and Stockholder's Equity $27,407
 $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, 201731
 $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, 201831
 $1,222
 $3,474
 $2,670
 $(31) $7,335
            
Balance at December 31, 201831
 $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, 201931
 $1,222
 $4,744
 $2,781
 $(27) $8,720
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



FIRST QUARTER 2019 vs. FIRST QUARTER 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
First Quarter 2019 vs. First Quarter 2018
(change in millions)
(% change)
$(8) (3.6)
Alabama Power's net income after dividends on preferred stock for the first quarter 2019 was $217 million compared to $225 million for the corresponding period in 2018. This decrease was primarily related to a decrease in retail revenues associated with milder weather and lower customer usage and an increase in non-fuel operations and maintenance expenses. These decreases to income were partially offset by an increase in retail revenues under Rate CNP Compliance associated with increases in average net investments and a decrease in income tax expense associated with the application in 2018 of the accounting order approved by the Alabama PSC in May 2018 related to the Tax Reform Legislation (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.
Retail Revenues
First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change)
$(72) (5.6)
In the first quarter 2019, retail revenues were $1.21 billion compared to $1.29 billion for the corresponding period in 2018.

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ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



Details of the changes in retail revenues were as follows:
 First Quarter 2019
 (in millions)
(% change)
Retail – prior year$1,285
  
Estimated change resulting from –   
Rates and pricing34
 2.6
Sales decline(17) (1.3)
Weather(25) (1.9)
Fuel and other cost recovery(64) (5.0)
Retail – current year$1,213
 (5.6)%
Revenues associated with changes in rates and pricing increased in the first quarter 2019 when compared to the corresponding period in 2018 primarily due to increased revenues under Rate CNP Compliance associated with increases in average net investments. See Note 2 to the financial statements under "Alabama Power" in Item 8 of the Form 10-K for additional information.
Revenues attributable to changes in sales decreased in the first quarter 2019 when compared to the corresponding period in 2018. Weather-adjusted commercial KWH sales decreased 3.5% in the first quarter 2019 and weather-adjusted residential KWH sales decreased 2.3% in the first quarter 2019 when compared to the corresponding period in 2018 primarily due to lower customer usage resulting from customer initiatives in energy savings for commercial customers and lower usage due to more energy-efficient residential appliances. Industrial KWH sales decreased 3.0% in the first quarter 2019 when compared to the corresponding period in 2018 as a result of a decrease in demand resulting from changes in production levels primarily in the primary metals, chemicals, and paper sectors, partially offset by increased demand in the pipeline sector.
Revenues resulting from changes in weather decreased in the first quarter 2019 due to milder weather. In the first quarter 2019, the resulting decreases were 3.3% and 1.7% for residential and commercial sales revenues, respectively.
Fuel and other cost recovery revenues decreased in the first quarter 2019 when compared to the corresponding period in 2018 primarily due to a decrease in generation.
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.
Wholesale Revenues Non-Affiliates
First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change)
$(13) (17.6)
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.

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ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



In the first quarter 2019, wholesale revenues from sales to non-affiliates were $61 million compared to $74 million for the corresponding period in 2018. The decrease was primarily due to a 10.1% decrease in the price of energy due to lower natural gas prices and a 9.4% decrease in KWH sales as a result of lower demand in the first quarter 2019 compared to the corresponding period in 2018.
Wholesale Revenues Affiliates
First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change)
$9 17.6
Wholesale revenues from sales to affiliated companies will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since 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 first quarter 2019, wholesale revenues from sales to affiliates were $60 million compared to $51 million for the corresponding period in 2018. The increase was primarily due to a 33.4% increase in KWH sales partially offset by a 12.6% decrease in the price of energy due to increased hydro generation in the first quarter 2019 as compared to the corresponding period in 2018.
Other Revenues
First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change)
$11 17.5
In the first quarter 2019, other revenues were $74 million compared to $63 million for the corresponding period in 2018. This increase was primarily due to an increase in OATT revenues and opportunity sales of natural gas.
Fuel and Purchased Power Expenses
 First Quarter 2019 vs. First Quarter 2018
 (change in millions) (% change)
Fuel$(25) (7.7)
Purchased power – non-affiliates(27) (42.2)
Purchased power – affiliates(16) (43.2)
Total fuel and purchased power expenses$(68)  
In the first quarter 2019, fuel and purchased power expenses were $359 million compared to $427 million for the corresponding period in 2018. The decrease was primarily due to a $53 million decrease related to the volume of KWHs generated (excluding hydro) and purchased and a $14 million decrease in the average cost of purchased power.
Fuel and purchased power energy transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through Alabama Power's energy cost recovery clause. See Note 2 to the financial statements under "Alabama Power – Rate ECR" in Item 8 of the Form 10-K for additional information.

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ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



Details of Alabama Power's generation and purchased power were as follows:
 First Quarter 2019
First Quarter 2018
Total generation (in billions of KWHs)
16 16
Total purchased power (in billions of KWHs)
1 1
Sources of generation (percent) —
   
Coal43 50
Nuclear23 23
Gas19 18
Hydro15 9
Cost of fuel, generated (in cents per net KWH) 
   
Coal2.78 2.69
Nuclear0.78 0.75
Gas2.57 2.87
Average cost of fuel, generated (in cents per net KWH)(a)
2.19 2.23
Average cost of purchased power (in cents per net KWH)(b)
5.75 7.10
(a)KWHs generated by hydro are excluded from the average cost of fuel, generated.
(b)Average cost of purchased power includes fuel, energy, and transmission purchased by Alabama Power for tolling agreements where power is generated by the provider.
Fuel
In the first quarter 2019, fuel expense was $301 million compared to $326 million for the corresponding period in 2018. The decrease was primarily due to a 79.7% increase in the volume of KWHs generated by hydro, a 12.7% decrease in the volume of KWHs generated by coal, and a 10.5% decrease in the average cost of natural gas per KWH generated, which excludes fuel associated with tolling agreements. The decrease was partially offset by a 4.6% increase in the volume of KWHs generated by natural gas and a 3.4% increase in the average cost of coal per KWH generated.
Purchased Power – Non-Affiliates
In the first quarter 2019, purchased power expense from non-affiliates was $37 million compared to $64 million for the corresponding period in 2018. The decrease was primarily related to a 28.3% decrease in the average cost of purchased power per KWH due to lower natural gas prices and a 19.7% 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 first quarter 2019, purchased power expense from affiliates was $21 million compared to $37 million for the corresponding period in 2018. The decrease was primarily related to a 48.6% decrease in the amount of energy purchased due to increased hydro generation, partially offset by an 11.4% increase in the average cost of purchased power per KWH as a result of firm transportation costs.
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.

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ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



Other Operations and Maintenance Expenses
First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change)
$22 5.7
In the first quarter 2019, other operations and maintenance expenses were $409 million compared to $387 million for the corresponding period in 2018. This increase was primarily due to increases of $8 million in environmental expenses, $6 million in certain compensation and benefit expenses, and $4 million in nuclear generation expenses primarily due to plant improvement projects.
Depreciation and Amortization
First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change)
$10 5.3
In the first quarter 2019, depreciation and amortization was $199 million compared to $189 million for the corresponding period in 2018. This increase was primarily due to additional plant in service associated with compliance-related steam, distribution, and transmission.
Other Income (Expense), Net
First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change)
$9 180.0
In the first quarter 2019, other income (expense), net was $14 million compared to $5 million for the corresponding period in 2018. This increase was primarily due to an increase in interest income from temporary cash investments and additional sales of non-utility property in 2019.
Income Taxes
First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change)
$(20) (24.4)
In the first quarter 2019, income taxes were $62 million compared to $82 million for the corresponding period in 2018. This decrease was primarily due to lower pre-tax earnings in the first 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

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ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



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. The costs, including capital expenditures, operations and maintenance costs, and costs reflected in ARO liabilities, required to comply with environmental laws and regulations and to achieve stated goals may impact future electric generating unit retirement and replacement decisions, results of operations, cash flows, and/or financial condition. 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. A major portion of these costs is expected to be recovered through existing ratemaking provisions. 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 these matterspending 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.
Income Tax Matters
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 – "Income Tax"Environmental Matters" of GeorgiaAlabama 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.
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 March 25, 2019, the Alabama Municipal Electric Authority and Cooperative Energy and SCS and the traditional electric operating companies (including Alabama Power) filed a formal settlement agreement with the FERC agreeing to a 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 ultimate outcome of this matter cannot be determined at this time; however, if approved by the FERC as filed, the OATT settlement would not have a material impact on the financial statements of Alabama Power.
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

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ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk,"RESULTS OF OPERATIONS



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
In connection with management's decision to retire Plant Gorgas, in February 2019, Alabama Power reclassified approximately $1.3 billion for Plant Gorgas Unit 10 from plant in service, net of depreciation to other utility plant, net and continued to depreciate the asset according to the original depreciation rates. On April 15, 2019, Alabama Power retired Plant Gorgas Units 8, 9, and 10 and reclassified approximately $740 million of the remaining net investment costs of the units to a regulatory asset to be recovered over the units' remaining useful lives as established prior to the decision to retire. Additionally, approximately $700 million of net capitalized asset retirement costs will be reclassified to a regulatory asset and recovered in accordance with accounting guidance provided by the Alabama PSC. See Note 2 to the financial statements under "Regulatory Matters"Alabama PowerGeorgia Power,"Environmental Accounting Order" and Note (H) to6 in Item 8 of the Condensed Financial Statements hereinForm 10-K for information regarding the Tax Reform Legislation and related regulatory actions.additional information.
Other Matters
GeorgiaAlabama Power is involved in various other matters that could affect future earnings, including matters being litigated and regulatory matters that could affect future earnings.matters. In addition, GeorgiaAlabama Power is subject to certain claims and legal actions arising in the ordinary course of business. GeorgiaAlabama 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 predicted at this time; however, for current proceedings not specifically reported in NoteNotes (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 GeorgiaAlabama Power's financial statements. See NoteNotes (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.
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.
Recently Issued Accounting Standards
See Note (A) to the Condensed Financial Statements herein for information regarding Alabama Power's recently adopted accounting standards.

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ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Alabama Power in Item 7 of the Form 10-K for additional information. Alabama Power's financial condition remained stable at March 31, 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 $146 million for the first three months of 2019, a decrease of $9 million as compared to the first three months of 2018. The decrease in net cash provided from operating activities was primarily due to timing of vendor payments and other current liabilities, partially offset by increased fuel cost recovery. Net cash used for investing activities totaled $511 million for the first three months of 2019 primarily related to additional capital expenditures for distribution, environmental, and transmission assets. Net cash provided from financing activities totaled $811 million for the first three 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 three months of 2019 include increases of $1.2 billion in total common stockholder's equity, primarily due to a $1.225 billion capital contribution from Southern Company, and $446 million in cash and cash equivalents. Other significant changes include decreases of $268 million in other accounts payable primarily due to the timing of vendor payments and $200 million in securities due within one year due to the maturity of long-term debt.
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 March 31, 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 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

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ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



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 March 31, 2019, Alabama Power had approximately $759 million of cash and cash equivalents. Committed credit arrangements with banks at March 31, 2019 were as follows:
Expires    
2019 2020 2022 Total Unused
(in millions)
$33
 $500
 $800
 $1,333
 $1,333
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 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 March 31, 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 March 31, 2019. At March 31, 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.
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$32
 2.7% $185
(*)Average and maximum amounts are based upon daily balances during the three-month period ended March 31, 2019. No short-term debt was outstanding at March 31, 2019.

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ALABAMA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS



Alabama Power believes the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and operating cash flows.
Credit Rating Risk
At March 31, 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 March 31, 2019, the maximum potential collateral requirements at a rating below BBB- and/or Baa3 totaled approximately $354 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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GEORGIA POWER COMPANY

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GEORGIA POWER COMPANY
CONDENSED STATEMENTS OF INCOME (UNAUDITED)

 For the Three Months
Ended March 31,
 2019 2018
 (in millions)
Operating Revenues:   
Retail revenues$1,668
 $1,798
Wholesale revenues, non-affiliates29
 44
Wholesale revenues, affiliates3
 10
Other revenues133
 109
Total operating revenues1,833
 1,961
Operating Expenses:   
Fuel299
 412
Purchased power, non-affiliates118
 121
Purchased power, affiliates176
 171
Other operations and maintenance446
 408
Depreciation and amortization240
 228
Taxes other than income taxes106
 108
Total operating expenses1,385
 1,448
Operating Income448
 513
Other Income and (Expense):   
Interest expense, net of amounts capitalized(96) (106)
Other income (expense), net40
 38
Total other income and (expense)(56) (68)
Earnings Before Income Taxes392
 445
Income taxes81
 93
Net Income$311
 $352
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

 For the Three Months
Ended March 31,
 2019 2018
 (in millions)
Net Income$311
 $352
Other comprehensive income (loss):   
Qualifying hedges:   
Reclassification adjustment for amounts included in net income,
net of tax of $- and $-, respectively
1
 1
Total other comprehensive income (loss)1
 1
Comprehensive Income$312
 $353
The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.

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GEORGIA POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
 For the Three Months
Ended March 31,
 2019 2018
 (in millions)
Operating Activities:   
Net income$311
 $352
Adjustments to reconcile net income to net cash provided from operating activities —   
Depreciation and amortization, total287
 280
Deferred income taxes127
 (38)
Pension, postretirement, and other employee benefits(35) (19)
Settlement of asset retirement obligations(34) (23)
Other, net(18) 28
Changes in certain current assets and liabilities —   
-Receivables91
 135
-Fossil fuel stock(41) 24
-Prepaid income taxes(73) 84
-Other current assets33
 9
-Accounts payable(166) (180)
-Accrued taxes(245) (191)
-Accrued compensation(67) (85)
-Other current liabilities42
 (3)
Net cash provided from operating activities212
 373
Investing Activities:   
Property additions(875) (681)
Nuclear decommissioning trust fund purchases(129) (255)
Nuclear decommissioning trust fund sales124
 250
Cost of removal, net of salvage(58) (26)
Change in construction payables, net of joint owner portion(38) (47)
Payments pursuant to LTSAs(2) (43)
Proceeds from asset dispositions7
 134
Other investing activities(9) 
Net cash used for investing activities(980) (668)
Financing Activities:   
Decrease in notes payable, net(19) 
Proceeds —   
FFB loan835
 
Pollution control revenue bonds343
 
Capital contributions from parent company27
 1,474
Redemptions and repurchases —   
Pollution control revenue bonds(108) (278)
Short-term borrowings
 (150)
Other long-term debt
 (100)
Payment of common stock dividends(394) (339)
Other financing activities(19) (6)
Net cash provided from financing activities665
 601
Net Change in Cash, Cash Equivalents, and Restricted Cash(103) 306
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period112
 852
Cash, Cash Equivalents, and Restricted Cash at End of Period$9
 $1,158
Supplemental Cash Flow Information:   
Cash paid during the period for —   
Interest (net of $8 and $6 capitalized for 2019 and 2018, respectively)$92
 $115
Noncash transactions — Accrued property additions at end of period607
 525
The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.

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GEORGIA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
Assets At March 31, 2019 At December 31, 2018
  (in millions)
Current Assets:    
Cash and cash equivalents $9
 $4
Restricted cash and cash equivalents 
 108
Receivables —    
Customer accounts receivable 550
 591
Unbilled revenues 179
 208
Under recovered fuel clause revenues 73
 115
Joint owner accounts receivable 170
 170
Affiliated 21
 39
Other accounts and notes receivable 241
 80
Accumulated provision for uncollectible accounts (2) (2)
Fossil fuel stock 272
 231
Materials and supplies 504
 519
Prepaid expenses 193
 142
Other regulatory assets 210
 199
Other current assets 48
 70
Total current assets 2,468
 2,474
Property, Plant, and Equipment:    
In service 38,015
 37,675
Less: Accumulated provision for depreciation 12,210
 12,096
Plant in service, net of depreciation 25,805
 25,579
Nuclear fuel, at amortized cost 565
 550
Construction work in progress 5,298
 4,833
Total property, plant, and equipment 31,668
 30,962
Other Property and Investments:    
Equity investments in unconsolidated subsidiaries 50
 51
Nuclear decommissioning trusts, at fair value 942
 873
Miscellaneous property and investments 73
 72
Total other property and investments 1,065
 996
Deferred Charges and Other Assets:    
Operating lease right-of-use assets, net of amortization 1,519
 
Deferred charges related to income taxes 518
 517
Other regulatory assets, deferred 4,921
 4,902
Other deferred charges and assets 379
 514
Total deferred charges and other assets 7,337
 5,933
Total Assets $42,538
 $40,365
The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.


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GEORGIA POWER COMPANY
CONDENSED BALANCE SHEETS (UNAUDITED)
Liabilities and Stockholder's Equity At March 31, 2019 At December 31, 2018
  (in millions)
Current Liabilities:    
Securities due within one year $973
 $617
Notes payable 275
 294
Accounts payable —    
Affiliated 448
 575
Other 827
 890
Customer deposits 278
 276
Accrued taxes 132
 377
Accrued interest 103
 105
Accrued compensation 112
 221
Asset retirement obligations 221
 202
Other regulatory liabilities 197
 169
Other current liabilities 305
 183
Total current liabilities 3,871
 3,909
Long-term Debt 10,108
 9,364
Deferred Credits and Other Liabilities:    
Accumulated deferred income taxes 3,192
 3,062
Deferred credits related to income taxes 3,079
 3,080
Accumulated deferred ITCs 259
 262
Employee benefit obligations 567
 599
Operating lease obligations 1,404
 
Asset retirement obligations, deferred 5,634
 5,627
Other deferred credits and liabilities 155
 139
Total deferred credits and other liabilities 14,290
 12,769
Total Liabilities 28,269
 26,042
Common Stockholder's Equity (See accompanying statements)
 14,269
 14,323
Total Liabilities and Stockholder's Equity $42,538
 $40,365
The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.

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GEORGIA POWER COMPANY
CONDENSED STATEMENTS OF 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, 20179
 $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, 20189
 $398
 $8,805
 $4,228
 $(11) $13,420
            
Balance at December 31, 20189
 $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, 20199
 $398
 $10,350
 $3,529
 $(8) $14,269
The accompanying notes as they relate to Georgia Power are an integral part of these condensed financial statements.


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GEORGIA POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS


FIRST QUARTER 2019 vs. FIRST QUARTER 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. Georgia Power is required to file a base rate case by July 1, 2019.
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 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.

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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 March 31, 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 MattersNuclear Construction" and Note (F) to the Condensed Financial Statements under "DOE Loan Guarantee Borrowings" herein for additional information.
RESULTS OF OPERATIONS
Net Income
First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change)
$(41) (11.6)
In the first quarter 2019, net income was $311 million compared to $352 million for the corresponding period in 2018. The decrease was primarily due to a decrease in retail revenues largely due to milder weather compared to the corresponding period in 2018 and higher non-fuel operations and maintenance expenses.
Retail Revenues
First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change)
$(130) (7.2)
In the first quarter 2019, retail revenues were $1.67 billion compared to $1.80 billion for the corresponding period in 2018.
Details of the changes in retail revenues were as follows:
 First Quarter 2019
 (in millions) (% change)
Retail – prior year$1,798
  
Estimated change resulting from –   
Rates and pricing9
 0.5
Sales growth5
 0.3
Weather(57) (3.2)
Fuel cost recovery(87) (4.8)
Retail – current year$1,668
 (7.2)%
Revenues associated with changes in rates and pricing increased in the first quarter 2019 when compared to the corresponding period in 2018 primarily due to the rate pricing effect of decreased customer usage and increases in revenues recognized under the NCCR tariff, partially offset by lower contributions from commercial and industrial customers with variable demand-driven pricing. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory MattersNuclear ConstructionRegulatory Matters" herein for additional information related to the NCCR tariff.
Revenues attributable to changes in sales increased in the first quarter 2019 when compared to the corresponding period in 2018. Weather-adjusted residential KWH sales increased 2.1% in the first quarter 2019 largely due to customer growth. Weather-adjusted commercial KWH sales decreased 1.1% in the first quarter 2019 largely due to a

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decline in average customer usage resulting from an increase in energy saving initiatives, partially offset by customer growth. Weather-adjusted industrial KWH sales were relatively flat in the first quarter 2019. The primary drivers were decreases in the textile and stone, clay, and glass sectors, largely offset by increases in the paper, primary and fabricated metal, and chemical sectors.
Fuel revenues and costs are allocated between retail and wholesale jurisdictions. Retail fuel cost recovery revenues decreased in the first quarter 2019 when compared to the corresponding period in 2018 primarily due to decreased energy sales driven by milder weather, 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
First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change)
$(15) (34.1)
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 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 first quarter 2019, wholesale revenues from sales to non-affiliates were $29 million compared to $44 million for the corresponding period in 2018. The decrease was due to a decrease in energy revenues primarily due to lower customer demand and scheduled generation outages.
Other Revenues
First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change)
$24 22.0
In the first quarter 2019, other revenues were $133 million compared to $109 million for the corresponding period in 2018. The increase was primarily due to revenue increases of $11 million from unregulated sales primarily associated with new energy conservation projects, $6 million from OATT sales, and $4 million from solar application fees.

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Fuel and Purchased Power Expenses
 First Quarter 2019 vs. First Quarter 2018
 (change in millions) (% change)
Fuel$(113) (27.4)
Purchased power – non-affiliates(3) (2.5)
Purchased power – affiliates5
 2.9
Total fuel and purchased power expenses$(111)  
In the first quarter 2019, total fuel and purchased power expenses were $593 million compared to $704 million in the corresponding period in 2018. The decrease was primarily due to a $130 million decrease related to the average cost of fuel and purchased power primarily related to lower energy prices and more rainfall for hydro generation, partially offset by a net increase of $19 million related to 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.
Details of Georgia Power's generation and purchased power were as follows:
 First Quarter 2019 First Quarter 2018
Total generation (in billions of KWHs)
13 16
Total purchased power (in billions of KWHs)
8 6
Sources of generation (percent) —
   
Gas50 44
Coal18 29
Nuclear26 24
Hydro6 3
Cost of fuel, generated (in cents per net KWH) 
   
Gas2.59 2.72
Coal3.23 3.36
Nuclear0.81 0.82
Average cost of fuel, generated (in cents per net KWH)
2.21 2.43
Average cost of purchased power (in cents per net KWH)(*)
3.94 5.38
(*)Average cost of purchased power includes fuel purchased by Georgia Power for tolling agreements where power is generated by the provider.
Fuel
In the first quarter 2019, fuel expense was $299 million compared to $412 million in the corresponding period in 2018. The decrease was primarily due to a 22.1% decrease in the volume of KWHs generated largely due to scheduled generation outages and milder weather, a 9.1% decrease in the average cost of fuel primarily related to lower natural gas and coal prices, and more rainfall for hydro generation.
Purchased Power – Non-Affiliates
In the first quarter 2019, purchased power expense from non-affiliates was $118 million compared to $121 million in the corresponding period in 2018. The decrease was primarily due to a 32.5% decrease in the average cost per KWH purchased primarily due to lower natural gas and coal prices, largely offset by a 35.2% increase in the volume

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of KWHs purchased primarily due to scheduled generation outages at Georgia Power-owned generating units. The volume increase also reflects 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.
Purchased Power – Affiliates
In the first quarter 2019, purchased power expense from affiliates was $176 million compared to $171 million in the corresponding period in 2018. The increase was primarily due to a 36.0% increase in the volume of KWHs purchased primarily due to scheduled generation outages at Georgia Power-owned generating units, partially offset by a 22.8% decrease in the average cost per KWH purchased primarily resulting from lower natural gas and coal prices. The increase in the volume of KWHs purchased was partially offset by the effect of classifying purchases from Gulf Power as non-affiliate beginning 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 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
First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change)
$38 9.3
In the first quarter 2019, other operations and maintenance expenses were $446 million compared to $408 million in the corresponding period in 2018. The increase was primarily due to increases of $16 million in certain compensation and benefit expenses, $14 million in scheduled generation outage expenses, $9 million of expenses from unregulated sales primarily associated with new energy conservation projects, and $6 million primarily due to the timing of vegetation management and other distribution-related maintenance expenses, partially offset by a decrease of $6 million in customer accounts and sales expenses.
Depreciation and Amortization
First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change)
$12 5.3
In the first quarter 2019, depreciation and amortization was $240 million compared to $228 million in the corresponding period in 2018. The increase was primarily due to additional plant in service.
Interest Expense, Net of Amounts Capitalized
First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change)
$(10) (9.4)
In the first quarter 2019, interest expense, net of amounts capitalized was $96 million compared to $106 million in the corresponding period in 2018. The decrease was primarily due to a $13 million decrease in interest expense associated with a decrease in outstanding borrowings, partially offset by an increase of $4 million related to PPAs

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with Southern Power accounted for as finance leases following the adoption of FASB ASC Topic 842, Leases (ASC 842). In prior periods, these expenses 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
First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change)
$(12) (12.9)
In first quarter 2019, income taxes were $81 million compared to $93 million in the corresponding period in 2018. The decrease was primarily due to lower pre-tax earnings and an increase in state ITCs, partially offset by an adjustment in 2018 related to the Tax Reform Legislation.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Georgia Power's future earnings potential. The level of Georgia Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Georgia Power's business of providing electric service. These factors include Georgia Power's ability to maintain a constructive regulatory environment that continues to allow for the timely recovery of prudently-incurred costs during a time of increasing costs, 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. The costs, including capital expenditures, operations and maintenance costs, and costs reflected in ARO liabilities, required to comply with environmental laws and regulations and to achieve stated goals may impact future electric generating unit retirement and replacement decisions, results of operations, cash flows, and/or financial condition. 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. 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.

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New or revised environmental laws and regulations could affect many areas of Georgia Power's operations. The impact of any such changes cannot be determined at this time. Environmental compliance costs could affect earnings if such costs cannot continue to be 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.
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 March 25, 2019, the Alabama Municipal Electric Authority and Cooperative Energy and SCS and the traditional electric operating companies (including Georgia Power) filed a formal settlement agreement with the FERC agreeing to a 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 ultimate outcome of this matter cannot be determined at this time; however, if approved by the FERC as filed, the OATT settlement would 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. Georgia Power is scheduled to file a base rate case by July 1, 2019, which may continue or modify these 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.
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

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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.
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 estimate0.4
Total project capital cost forecast(a)(b)
8.4
Net investment as of March 31, 2019(b)
(4.9)
Remaining estimate to complete(a)
$3.5
(a)Excludes financing costs expected to be capitalized through AFUDC of approximately $325 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 $1.9 billion had been incurred through March 31, 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 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.
As construction continues, 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), any of which may require additional labor and/or materials; or other issues could arise and change the projected schedule and estimated cost. Monthly construction production targets established as part of a strategy to maintain and build margin to the approved in-service dates will continue to increase significantly throughout 2019. To meet these increasing monthly targets, existing craft construction productivity must improve and additional craft laborers 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

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construction and operating licenses, including inspections by Southern Nuclear and the NRC that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the NRC. Various design and other licensing-based compliance matters, including the timely resolution of ITAAC and the related approvals by the NRC, may arise, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs.
The ultimate outcome of these matters cannot be determined at this time. However, any extension of the 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) 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

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applicable certified costs through annual adjustments to the NCCR tariff up to the certified capital cost of $4.418 billion. At March 31, 2019, Georgia Power had recovered approximately $1.9 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 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 $75 million in 2019 and an aggregate of approximately $635 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

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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 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). In addition, the staff of the Georgia PSC requested, and Georgia Power agreed, to report the results of the cost and schedule validation process to the Georgia PSC (which is expected to occur by May 1, 2019) and to file its twentieth VCM report concurrently with the twenty-first VCM report by August 31, 2019.
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 March 31, 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 predicted 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.

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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 NoteNotes 1, 5, and 6 to the financial statements of Georgia Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Georgia Power's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Georgia Power in Item 7 of the Form 10-K for a complete discussion of Georgia Power's critical accounting policies and estimates.
Estimated Cost, Schedule, and Rate Recovery for the Construction of Plant Vogtle Units 3 and 4
In December 2016, the Georgia PSC approved the Vogtle Cost Settlement Agreement, which resolved certain prudency matters in connection with Georgia Power's fifteenth VCM report. In December 2017, the Georgia PSC approved Georgia Power's seventeenth VCM report, which included a recommendation to continue construction of Plant Vogtle Units 3 and 4, with Southern Nuclear serving as project manager and Bechtel serving as the primary construction contractor, as well as a modification of the Vogtle Cost Settlement Agreement. The Georgia PSC's related order stated that under the modified Vogtle Cost Settlement Agreement, (i) none of the $3.3 billion of costs incurred through December 31, 2015 should be disallowed as imprudent; (ii) capital costs incurred up to $5.68 billion would be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs; (iii) Georgia Power would have the burden of proof to show that any capital costs above $5.68 billion were prudent; (iv) Georgia Power's total project capital cost forecast of $7.3 billion (net of $1.7 billion received under the Guarantee Settlement Agreement and $188 million in Customer Refunds recognized as a regulatory liability in

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2017) was found reasonable and did not represent a cost cap; and (v) prudence decisions would be made subsequent to achieving fuel load for Unit 4.
In its order, the Georgia PSC also stated if other conditions change and assumptions upon which Georgia Power's seventeenth VCM report are based do not materialize, the Georgia PSC reserved the right to reconsider the decision to continue construction.
In the second quarter 2018, Georgia Power revised its base cost forecast and estimated contingency to complete construction and start-up of Plant Vogtle Units 3 and 4 to $8.0 billion and $0.4 billion, respectively, for a total project capital cost forecast of $8.4 billion (net of $1.7 billion received under the Guarantee Settlement Agreement and $188 million in Customer Refunds recognized as a regulatory liability in 2017). Although Georgia Power believes these incremental costs are reasonable and necessary to complete the project and the Georgia PSC has stated the $7.3 billion estimate included in the seventeenth VCM proceeding does not represent a cost cap, Georgia Power does not intend to seek rate recovery for the $0.7 billion increase in costs included in the revised base capital cost forecast, which will be filed with the Georgia PSC in the nineteenth VCM report on August 31, 2018. In connection with future VCM filings, Georgia Power may request the Georgia PSC to evaluate costs included in the revised construction contingency estimate for rate recovery as and when they are appropriately included in the base capital cost forecast. After considering the significant level of uncertainty that exists regarding the future recoverability of costs included in the construction contingency estimate since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in these future regulatory proceedings, Georgia Power has recorded a total pre-tax charge to income of $1.1 billion ($0.8 billion after tax) as of June 30, 2018.
Georgia Power's revised cost estimate reflects an expected in-service date of November 2021 for Unit 3 and November 2022 for Unit 4.
As construction continues, challenges with management of contractors, subcontractors, and vendors; labor productivity, availability, and/or cost escalation; procurement, fabrication, delivery, assembly, and/or installation, including any required engineering changes, of plant systems, structures, and components (some of which are based on new technology that is just beginning initial operation in the global nuclear industry at this scale); or other issues could arise and change the projected schedule and estimated cost.
There have been technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4 at the federal and state level and additional challenges may arise. Processes are in place that are designed to assure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating licenses, including inspections by Southern Nuclear and the NRC that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the NRC. Various design and other licensing-based compliance matters, including the timely resolution of Inspections, Tests, Analyses, and Acceptance Criteria and the related approvals by the NRC, may arise, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs.
The ultimate outcome of these matters cannot be determined at this time. Any extension of the in-service dates of November 2021 for Unit 3 and November 2022 for Unit 4 is currently estimated to result in additional base capital costs of approximately $50 million per month, based on Georgia Power's ownership interests, and AFUDC of approximately $12 million per month. While Georgia Power is not precluded from seeking recovery of any future capital cost forecast increase, management will ultimately determine whether or not to seek recovery. Any further changes to the capital cost forecast that are not expected to be recoverable through regulated rates will be required to be charged to income and such charges could be material.

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Given the significant complexity involved in estimating the future costs to complete construction and start-up of Plant Vogtle Units 3 and 4 and the significant management judgment necessary to assess the related uncertainties surrounding future rate recovery of any projected cost increases, as well as the potential impact on Georgia Power's results of operations and cash flows, Georgia Power considers these items to be critical accounting estimates. See Note 3 to the financial statements of Georgia Power under "Retail Regulatory Matters – Nuclear Construction" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Nuclear Construction" herein for additional information.
Recently Issued Accounting Standards
See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Recently Issued Accounting Standards" of Georgia Power in Item 7 of the Form 10-K for additional information regarding ASU No. 2016-02, Leases (Topic 842). See Note (A) to the Condensed Financial Statements herein for information regarding Georgia Power's recently adopted accounting standards.
FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Georgia Power in Item 7 of the Form 10-K for additional information. Georgia Power's financial condition remained stable at June 30, 2018.March 31, 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 $1.07 billion$212 million for the first sixthree months of 20182019 compared to $482$373 million for the corresponding period in 2017.2018. The increasedecrease was primarily due to increased fuel cost recovery, a decrease in current income taxes related to the Tax Reform Legislation, income tax refunds received, and the timing of fossil fuel stock purchases and higher payments for property tax payments.taxes and municipal franchise fees. Net cash used for investing activities totaled $1.39 billion$980 million for the first sixthree months of 20182019 primarily related to installation of equipment to comply with environmental standards and construction of generation, transmission, and distribution facilities.facilities, including approximately $360 million related to the construction of Plant Vogtle Units 3 and 4. Net cash used forprovided from financing activities totaled $520$665 million for the first sixthree months of 20182019 primarily due to borrowings from the redemptionFFB for construction of Plant Vogtle Units 3 and repurchase4 and the reoffering of senior notes, paymentspollution control revenue bonds, partially offset by payment of common stock dividends and the redemption of pollution control revenue bond purchases, partially offset by capital contributions from Southern Company.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 sixthree months of 20182019 include a decreaserecording $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 $1.1 billion in long-term debt (including securities due within one year) primarily due to borrowings from the redemptionFFB for construction of Plant Vogtle Units 3 and repurchase of senior notes4 and the purchasereoffering of pollution control revenue bonds previously purchased and held by Georgia Power, and an increase of $1.0$0.7 billion in property, plant, and equipment to comply with environmental standards and the construction of generation, transmission, and distribution facilities, including $0.6 billion relatedfacilities. See Note (L) to the constructionCondensed Financial Statements herein for additional information on the adoption of Plant Vogtle Units 3ASC 842. Also see Notes (B) and 4. The increase in property, plant, and equipment was more than offset by a $1.1 billion decrease due to the charge related to the construction of Plant Vogtle Units 3 and 4. Total common stockholder's equity increased $0.8 billion primarily due to a $1.5 billion increase in paid-in capital resulting from capital contributions received from Southern Company, partially offset by a $0.7 billion decrease in retained earnings primarily due to the charge related to Plant Vogtle Units 3 and 4. See Note (B)(F) to the Condensed Financial Statements under "Nuclear Construction""Georgia PowerNuclear Construction" and "DOE Loan Guarantee Borrowings," respectively, herein for additional information regarding Plant Vogtle Units 3 and 4.4 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 $509 million will be required through June 30, 2019 to fund maturities of long-term debt. See "Sources of Capital" herein for additional

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of Georgia Power's capital requirements and contractual obligations. Approximately $973 million will be required through March 31, 2020 to fund maturities of long-term debt. See "Sources of Capital" herein for additional information. Also see FUTURE EARNINGS POTENTIAL – "Retail Regulatory MattersNuclear Construction" for additional information regarding Plant Vogtle Units 3 and 4.
Georgia Power's construction program is currently estimated to total approximately $3.5 billion for 2018, $3.6 billion for 2019, $2.8 billion for 2020, $2.7 billion for 2021, and $2.4 billion for 2022. These amounts include expenditures of approximately $1.4 billion, $1.4 billion, $0.9 billion, $1.0 billion, and $0.6 billion for the construction of Plant Vogtle Units 3 and 4 in 2018, 2019, 2020, 2021, and 2022, respectively. These amounts also include capital expenditures related to contractual purchase commitments for nuclear fuel and capital expenditures covered under LTSAs. Estimated capital expenditures to comply with environmental laws and regulations included in these amounts are $0.5 billion, $0.1 billion, $0.2 billion, $0.2 billion, and $0.2 billion for 2018, 2019, 2020, 2021, and 2022, respectively. These estimated expenditures do not include any potential compliance costs associated with the regulation of CO2 emissions from fossil fuel-fired electric generating units.
Georgia Power also anticipates costs associated with closure and monitoring of ash ponds in accordance with the CCR Rule, which are reflected in Georgia Power's ARO liabilities. These costs, which are expected to change as Georgia Power continues to refine its assumptions underlying the cost estimates and evaluate the method and timing of compliance activities, are estimated to be $0.2 billion per year for 2018 through 2020 and $0.3 billion per year for 2021 and 2022. For information regarding expected changes to these cost estimates during the second half of 2018, see FUTURE EARNINGS POTENTIAL – "Environmental MattersEnvironmental Laws and Regulations – Coal Combustion Residuals" and Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein. Also see Note 1 to the financial statements of Georgia Power under "Asset Retirement Obligations and Other Costs of Removal" in Item 8 of the Form 10-K for additional information on AROs.
The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental laws and regulations; the outcome of any legal challenges to environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing generating units, to meet regulatory requirements; changes in FERC rules and regulations; Georgia PSC approvals; changes in the expected environmental compliance program; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; storm impacts; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. The construction program also includes Plant Vogtle Units 3 and 4, which includes components based on new technology that is just beginningonly 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,productivity; challenges with management of contractors, subcontractors, or vendors,vendors; adverse weather conditions,conditions; shortages, andincreased costs, or inconsistent quality of equipment, materials, and labor,labor; contractor or supplier delay,delay; non-performance under construction, operating, or other agreements,agreements; operational readiness, including specialized operator training and required site safety programs, unforeseenprograms; engineering or design problems,problems; design and other licensing-based compliance matters, including the timely resolution of ITAAC and the related approvals by the NRC; challenges with start-up activities, (includingincluding major equipment failure and system integration),integration; and/or operational performance. See Note 32 to the financial statements of Georgiaunder "Georgia Power under "Retail Regulatory Matters – Nuclear Construction" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Georgia PowerNuclear Construction" herein for information regarding additional factors that may impact construction expenditures.
Sources of Capital
Georgia Power plans to obtain the funds required for construction and other purposes from sources similar to those used in the past, which were primarily from operating cash flows, external security issuances, borrowings from financial institutions, equity contributions from Southern Company, and borrowings from the FFB. However, the amount, type, and timing of any future financings, if needed, will depend upon regulatory approvals, prevailing market conditions, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL

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CONDITION AND LIQUIDITY – "Sources of Capital" of Georgia Power in Item 7 of the Form 10-K for additional information.
In 2014, Georgia Power entered into a loan guarantee agreement with the DOE and, in March 2019, 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.
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 ofthrough the FFB in an amount up to $3.46approximately $5.130 billion, (not toprovided that total aggregate borrowings under the FFB Credit Facilities may not exceed 70% of (i) Eligible Project Costs) to be madeCosts minus (ii) approximately $1.492 billion (reflecting the amounts received by Georgia Power under a multi-advance credit facility (FFB Credit Facility) among Georgia Power, the DOE, andGuarantee Settlement Agreement less the FFB. As of June 30, 2018,Customer Refunds). At March 31, 2019, Georgia Power had borrowed $2.6$3.46 billion under the FFB Credit Facility. In July 2017, Georgia Power entered into an amendment to the Loan Guarantee Agreement, which provides that further advances are conditioned upon the DOE's approval of any agreements entered into in replacement of the Vogtle 3 and 4 Agreement and satisfaction of certain other conditions.Facilities.
In September 2017, the DOE issued a conditional commitment to Georgia Power for up to approximately $1.67 billion of additional guaranteed loans under the Loan Guarantee Agreement. This conditional commitment expires on September 30, 2018, subject to any further extension approved by the DOE. Final approval and issuance of these additional loan guarantees by the DOE cannot be assured and are subject to the negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions, including the Vogtle Owners' votes to continue construction. See Note 6 to the financial statements of Georgia Power under "DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements under "DOE Loan Guarantee Borrowings" herein for additional information regarding the Amended and Restated Loan Guarantee Agreement, including applicable covenants,

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events of default, mandatory prepayment events, (including any decision not to continue construction of Plant Vogtle Units 3 and 4), and additional conditions to borrowing. Also see Note (B) to the Condensed Financial Statements under "Georgia PowerNuclear Construction" herein for additional information regarding Plant Vogtle Units 3 and 4.
At June 30, 2018, Georgia Power's current liabilities exceeded current assets by $1.2 billion primarily due to long-term debt that is due within one year of $509 million and notes payable of $480 million. Georgia Power's current liabilities frequently exceed current assets because of scheduled maturities of long-term debt and the periodic use of short-term debt as a funding source, as well as significant seasonal fluctuations in cash needs. At March 31, 2019, Georgia Power intendsPower's current liabilities exceeded current assets by $1.4 billion primarily due to utilize operating cash flows, external security issuances, borrowings from financial institutions, equity contributions from Southern Company,long-term debt that is due within one year of $973 million and borrowings from the FFB to fund its short-term capital needs. Georgia Power has substantial cash flow from operating activities and access to the capital markets and financial institutions to meet liquidity needs.notes payable of $275 million.
At June 30, 2018,March 31, 2019, Georgia Power had approximately $11$9 million of cash and cash equivalents. Georgia Power's committed credit arrangement with banks at June 30, 2018 was $1.75 billion at March 31, 2019, of which $1.74 billion was unused. This credit arrangement expires in 2022.
This bank credit arrangement contains a covenant that limits debt levels and contains a cross-acceleration provision to other indebtedness (including guarantee obligations) of Georgia Power. Such cross-acceleration provision to other indebtedness would trigger an event of default if Georgia Power defaulted on indebtedness, the payment of which was then accelerated. At June 30, 2018,March 31, 2019, Georgia Power was in compliance with this covenant. This bank credit arrangement does not contain a material adverse change clause at the time of borrowing.
Subject to applicable market conditions, Georgia Power expects to renew or replace this credit arrangement as needed prior to expiration. In connection therewith, Georgia Power may extend the maturity date and/or increase or decrease the lending commitments thereunder.
See Note 68 to the financial statements of Georgia Power under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
A portion of the $1.74 billion unused credit with banks is allocated to provide liquidity support to Georgia Power's pollution control revenue bonds and commercial paper program. The amount of variable rate pollution control revenue bonds

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outstanding requiring liquidity support as of June 30, 2018March 31, 2019 was approximately $550 million. In addition, at June 30, 2018,March 31, 2019, Georgia Power had $232$345 million of pollution control revenue bonds outstanding that were required to be remarketed within the next 12 months. Subsequent to March 31, 2019, Georgia Power purchased and held approximately $115 million of outstanding pollution control revenue bonds required to be remarketed.
Georgia Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Georgia Power and the other traditional electric operating companies. Proceeds from such issuances for the benefit of Georgia Power are loaned directly to Georgia Power. The obligations of each traditional electric operating company under these arrangements are several and there is no cross-affiliate credit support. Short-term borrowings are included in notes payable in the balance sheets.
Details of short-term borrowings were as follows:
 Short-term Debt at June 30, 2018 
Short-term Debt During the Period(*)
 
Amount
Outstanding
 
Weighted
Average
Interest
Rate
 
Average
Amount
Outstanding
 
Weighted
Average
Interest
Rate
 
Maximum
Amount
Outstanding
 (in millions)   (in millions)   (in millions)
Commercial paper$480
 2.4% $120
 2.3% $495
 
Short-term Debt
at March 31, 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$275
 2.8% $437
 2.9% $935
(*)Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 2018.March 31, 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.

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Credit Rating Risk
At June 30, 2018,March 31, 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, 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, 2018March 31, 2019 were as follows:
Credit RatingsMaximum Potential
Collateral
Requirements
Maximum Potential
Collateral
Requirements
(in millions)(in millions)
At BBB- and/or Baa3$87
$92
Below BBB- and/or Baa3$1,020
$1,102
Included in these amounts are certain agreements that could require collateral in the event that Georgia Power or Alabama Power (affiliate company(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.
On February 28, 2018, Fitch downgraded the senior unsecured long-term debt rating of Georgia Power to A from A+ with a negative outlook.
As a result of the Tax Reform Legislation, certain financial metrics, such as the funds from operations to debt percentage, used by the credit rating agencies to assess Southern Company and its subsidiaries, including Georgia

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Power, may be negatively impacted. TheA settlement agreement between Georgia Power and the staff of the Georgia PSC regarding the retail rate impact of the Tax Reform Settlement AgreementLegislation, as approved by the Georgia PSC on April 3, 2018, is expected to help mitigate these potential adverse impacts to certain credit metrics by allowing a higher retail equity ratio until the conclusion of Georgia Power's next base rate case.case, which is scheduled to be filed by July 1, 2019. See Note 32 to the financial statements of Georgiaunder "Georgia Power under "Retail Regulatory Matters – Rate Plans" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory MattersGeorgia PowerRate Plans" herein for additional information.
Financing Activities
In January 2018,2019, Georgia Power repaid its outstanding $150redeemed approximately $13 million, $20 million, and $100 million floating rate bank loans due May 31, 2018 and October 26, 2018, respectively.
In March 2018, Georgia Power purchased and held $104.6$75 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 20131992, Eighth Series 1994, and $173Second 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. Georgia Power may reoffer these bonds to the public at a later date.2009;
In April 2018, Georgia Power purchased and held $55approximately $105 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), FifthFirst Series 1994. Georgia Power may reoffer these bonds to the public at a later date.2013; and
Also in April 2018, Georgia Power redeemed all $250 million aggregate principal amount of its Series 2008B 5.40% Senior Notes due June 1, 2018.
In May 2018, through cash tender offers, Georgia Power repurchased and retired $89 million of the $250 million aggregate principal amount outstanding of its Series 2007A 5.65% Senior Notes due March 1, 2037, $326 million of the $500 million aggregate principal amount outstanding of its Series 2009A 5.95% Senior Notes due February 1, 2039, and $335 million of the $600 million aggregate principal amount outstanding of its Series 2010B 5.40% Senior Notes due June 1, 2040, for an aggregate purchase price, excluding accrued and unpaid interest, of $902 million.
In June 2018, Georgia Power purchased and held $65$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.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS


Subsequent to March 31, 2019, Georgia Power purchased and held the following pollution control revenue bonds, which may reoffer these bondsbe reoffered to the public at a later date.date:
$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 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.

GULF POWER COMPANY

GULF POWER COMPANY
CONDENSED STATEMENTS OF INCOME (UNAUDITED)
 For the Three Months
Ended June 30,
 For the Six Months
Ended June 30,
 2018
2017 2018 2017
 (in millions) (in millions)
Operating Revenues:       
Retail revenues$301
 $318
 $591
 $596
Wholesale revenues, non-affiliates13
 12
 26
 30
Wholesale revenues, affiliates14
 10
 42
 47
Other revenues16
 17
 33
 34
Total operating revenues344
 357
 692
 707
Operating Expenses:       
Fuel91
 88
 173
 196
Purchased power44
 44
 90
 78
Other operations and maintenance90
 90
 166
 176
Depreciation and amortization48
 35
 95
 53
Taxes other than income taxes28
 28
 58
 55
Loss on Plant Scherer Unit 3
 
 
 33
Total operating expenses301
 285
 582
 591
Operating Income43
 72
 110
 116
Other Income and (Expense):       
Interest expense, net of amounts capitalized(13) (13) (26) (24)
Other income (expense), net1
 2
 3
 3
Total other income and (expense)(12) (11) (23) (21)
Earnings Before Income Taxes31
 61
 87
 95
Income taxes (benefit)(11) 24
 3
 38
Net Income42
 37
 84
 57
Dividends on Preference Stock
 2
 
 4
Net Income After Dividends on Preference Stock$42
 $35
 $84
 $53
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
 For the Three Months
Ended June 30,
 For the Six Months
Ended June 30,
 2018 2017 2018 2017
 (in millions) (in millions)
Net Income$42
 $37
 $84
 $57
Other comprehensive income (loss):       
Qualifying hedges:       
Changes in fair value, net of tax of
$-, $-, $-, and $(1), respectively

 (1) 
 (1)
Total other comprehensive income (loss)
 (1) 
 (1)
Comprehensive Income$42
 $36
 $84
 $56
The accompanying notes as they relate to Gulf Power are an integral part of these condensed financial statements.

GULF POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
 For the Six Months
Ended June 30,
 2018 2017
 (in millions)
Operating Activities:   
Net income$84
 $57
Adjustments to reconcile net income to net cash provided from operating activities —   
Depreciation and amortization, total98
 56
Deferred income taxes(21) 19
Loss on Plant Scherer Unit 3
 33
Other, net(3) (3)
Changes in certain current assets and liabilities —   
-Receivables9
 (25)
-Other current assets(2) 14
-Accounts payable(16) 3
-Accrued taxes18
 7
-Accrued compensation(15) (17)
-Over recovered regulatory clause revenues5
 (19)
-Other current liabilities
 (1)
Net cash provided from operating activities157
 124
Investing Activities:   
Property additions(135) (97)
Cost of removal, net of salvage(14) (9)
Change in construction payables(3) (14)
Other investing activities(6) (3)
Net cash used for investing activities(158) (123)
Financing Activities:   
Increase (decrease) in notes payable, net45
 (190)
Proceeds —   
Common stock issued to parent
 175
Capital contributions from parent company37
 5
Senior notes
 300
Redemptions —   
Preference stock
 (150)
Senior notes
 (85)
Payment of common stock dividends(77) (63)
Other financing activities(1) (4)
Net cash provided from (used for) financing activities4
 (12)
Net Change in Cash, Cash Equivalents, and Restricted Cash3
 (11)
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period28
 56
Cash, Cash Equivalents, and Restricted Cash at End of Period$31
 $45
Supplemental Cash Flow Information:   
Cash paid during the period for —   
Interest (net of $- and $- capitalized for 2018 and 2017, respectively)$25
 $22
Income taxes, net21
 7
Noncash transactions — Accrued property additions at end of period22
 19
The accompanying notes as they relate to Gulf Power are an integral part of these condensed financial statements.

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


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

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GULF POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

SECOND QUARTER 2018 vs. SECOND QUARTER 2017
AND
YEAR-TO-DATE 2018 vs. YEAR-TO-DATE 2017


OVERVIEW
Gulf Power operates as a vertically integrated utility providing electric service to retail customers within its traditional service territory located in northwest Florida and to wholesale customers in the Southeast.
On May 20, 2018, Southern Company entered into a stock purchase agreement with NextEra Energy to sell Gulf Power for an aggregate cash purchase price of $5.75 billion (less the amount of indebtedness assumed at closing, which is currently estimated at approximately $1.4 billion), subject to certain adjustments. The completion of the sale is subject to the satisfaction or waiver of certain closing conditions and is expected to occur in the first half of 2019. The ultimate outcome of this matter cannot be determined at this time. See Note (J) to the Condensed Financial Statements under "Southern Company's Sale of Gulf Power" herein for additional information.
Many factors affect the opportunities, challenges, and risks of Gulf Power's business of providing electric service. These factors include the ability to maintain a constructive regulatory environment, to maintain and grow energy sales and customers, and to effectively manage and secure timely recovery of costs. These costs include those related to projected long-term demand growth, stringent environmental standards, reliability, restoration following major storms, fuel, and capital expenditures. Gulf Power has various regulatory mechanisms that operate to address cost recovery. Effectively operating pursuant to these regulatory mechanisms and appropriately balancing required costs and capital expenditures with customer prices will continue to challenge Gulf Power for the foreseeable future.
As a continuation of a settlement agreement approved by the Florida PSC in April 2017 (2017 Gulf Power Rate Case Settlement Agreement), on March 26, 2018, the Florida PSC approved a stipulation and settlement agreement among Gulf Power and three intervenors addressing the retail revenue requirement effects of the Tax Reform Legislation (Gulf Power Tax Reform Settlement Agreement).
The Gulf Power Tax Reform Settlement Agreement results in annual reductions to Gulf Power's revenues of $18.2 million from base rates and $15.6 million from environmental cost recovery rates, implemented April 1, 2018, and also provides for a one-time refund of $69.4 million for the retail portion of unprotected (not subject to normalization) deferred tax liabilities through a reduced fuel cost recovery rate over the remainder of 2018. Through June 30, 2018, approximately $28 million of this refund has been reflected in customer bills. As a result of the Gulf Power Tax Reform Settlement Agreement, the Florida PSC also approved an increase in Gulf Power's maximum equity ratio from 52.5% to 53.5% for all retail regulatory purposes.
As part of the Gulf Power Tax Reform Settlement Agreement, a limited scope proceeding to address protected deferred tax liabilities consistent with IRS normalization principles was initiated on April 30, 2018. Pending resolution of this proceeding, Gulf Power is deferring the related amounts for 2018 as a regulatory liability. Through June 30, 2018, amounts deferred totaled $5 million. Unless otherwise agreed to by the parties to the Gulf Power Tax Reform Settlement Agreement, amounts recorded in this regulatory liability will be refunded to retail customers in 2019 through Gulf Power's fuel cost recovery rates. The ultimate outcome of this matter cannot be determined at this time.
See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Retail Base Rate Cases" in Item 8 of the Form 10-K for additional information.
Gulf Power continues to focus on several key performance indicators including, but not limited to, customer satisfaction, plant availability, system reliability, and net income.

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FINANCIAL CONDITION AND RESULTS OF OPERATIONS

RESULTS OF OPERATIONS
Net Income
Second Quarter 2018 vs. Second Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$7 20.0 $31 58.5
Gulf Power's net income after dividends on preference stock for the second quarter 2018 was $42 million compared to $35 million for the corresponding period in 2017. The increase was primarily due to higher retail base revenues, partially offset by depreciation credits recognized in 2017. In addition, the increase in net income reflects lower federal income tax expense as a result of the Tax Reform Legislation, partially offset by a reduction in retail revenues related to the Gulf Power Tax Reform Settlement Agreement.
Gulf Power's net income after dividends on preference stock for year-to-date 2018 was $84 million compared to $53 million for the corresponding period in 2017. The increase was primarily due to higher retail base revenues and the first quarter 2017 write-down of $32.5 million ($20 million after tax) of Gulf Power's ownership of Plant Scherer Unit 3 in accordance with the 2017 Gulf Power Rate Case Settlement Agreement, partially offset by depreciation credits recognized in 2017. In addition, the increase in net income reflects lower federal income tax expense as a result of the Tax Reform Legislation, partially offset by a reduction in retail revenues related to the Gulf Power Tax Reform Settlement Agreement.
See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Retail Base Rate Cases" in Item 8 of the Form 10-K for additional information regarding the 2017 Gulf Power Rate Case Settlement Agreement.
Retail Revenues
Second Quarter 2018 vs. Second Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(17) (5.3) $(5) (0.8)
In the second quarter 2018, retail revenues were $301 million compared to $318 million for the corresponding period in 2017. For year-to-date 2018, retail revenues were $591 million compared to $596 million for the corresponding period in 2017.
Details of the changes in retail revenues were as follows:
 Second Quarter 2018 Year-to-Date 2018
 (in millions) (% change) (in millions) (% change)
Retail – prior year$318
   $596
  
Estimated change resulting from –       
Rates and pricing(20) (6.3) (15) (2.5)
Sales growth2
 0.7
 4
 0.7
Weather1
 0.3
 10
 1.7
Fuel and other cost recovery
 
 (4) (0.7)
Retail – current year$301
 (5.3)% $591
 (0.8)%
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters" of Gulf Power in Item 7 and Note 1 to the financial statements of Gulf Power under "Revenues" and Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information regarding Gulf Power's retail base rate case and cost recovery clauses,

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

including Gulf Power's fuel cost recovery, purchased power capacity recovery, environmental cost recovery, and energy conservation cost recovery clauses.
Revenues associated with changes in rates and pricing decreased in the second quarter and year-to-date 2018 when compared to the corresponding periods in 2017 primarily due to a decrease in revenues effective January 1, 2018 due to the Gulf Power Tax Reform Settlement Agreement, partially offset by an increase in retail base rates effective July 2017 in accordance with the 2017 Gulf Power Rate Case Settlement Agreement.
Revenues attributable to changes in sales increased in the second quarter 2018 when compared to the corresponding period in 2017. For the second quarter 2018, weather-adjusted KWH sales to residential customers increased 3.2% due to customer growth. Weather-adjusted KWH sales to commercial customers increased 1.0% due to customer growth, partially offset by lower energy usage resulting from energy efficiency improvements in appliances and lighting. KWH sales to industrial customers decreased 4.5% for the second quarter 2018 primarily due to changes in customers' operations.
Revenues attributable to changes in sales increased for year-to-date 2018 when compared to the corresponding period in 2017. For year-to-date 2018, weather-adjusted KWH sales to residential customers increased 2.7% due to customer growth. Weather-adjusted KWH sales to commercial customers increased 0.4% due to customer growth, partially offset by lower energy usage resulting from energy efficiency improvements in appliances and lighting. KWH sales to industrial customers decreased 0.7% year-to-date 2018 primarily due to changes in customers' operations.
Fuel and other cost recovery revenues remained essentially flat in the second quarter 2018 when compared to the corresponding period in 2017, primarily due to higher recoverable environmental costs, offset by lower recoverable costs under the purchased power capacity and fuel cost recovery clauses. Fuel and other cost recovery revenues decreased year-to-date 2018 when compared to the corresponding period in 2017, primarily due to lower recoverable costs under the purchased power capacity and fuel cost recovery clauses, partially offset by higher environmental recoverable costs. Fuel and other cost recovery provisions include fuel expenses, the energy component of purchased power costs, purchased power capacity costs, the difference between projected and actual costs and revenues related to energy conservation and environmental compliance, and a credit for certain wholesale revenues as a result of the 2017 Gulf Power Rate Case Settlement Agreement.
See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses" and " – Retail Base Rate Cases" in Item 8 of the Form 10-K for additional information regarding cost recovery clauses and the 2017 Gulf Power Rate Case Settlement Agreement, respectively. Also see FUTURE EARNINGS POTENTIAL – "Retail Regulatory MattersRetail Base Rate Case" herein for additional information regarding the Gulf Power Tax Reform Settlement Agreement.
Wholesale Revenues – Non-Affiliates
Second Quarter 2018 vs. Second Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$1 8.3 $(4) (13.3)
Wholesale revenues from sales to non-affiliates consist of long-term sales agreements to other utilities in Florida and Georgia and short-term opportunity sales. Capacity revenues from the long-term sales agreements represent the greatest contribution to net income. The energy is generally sold at variable cost. Short-term opportunity sales are made at market-based rates that generally provide a margin above Gulf Power's variable cost of energy. Wholesale energy revenues from sales to non-affiliates will vary depending on fuel prices, the market prices of wholesale energy compared to the cost of Gulf Power's and the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation.

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For year-to-date 2018, wholesale revenues from sales to non-affiliates were $26 million compared to $30 million for the corresponding period in 2017. The decrease was primarily due to a 24.7% decrease in KWH sales resulting from lower opportunity sales due to maintenance outages at Gulf Power generating units.
Wholesale Revenues – Affiliates
Second Quarter 2018 vs. Second Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$4 40.0 $(5) (10.6)
Wholesale revenues from sales to affiliated companies will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales are made in accordance with the IIC, as approved by the FERC. These transactions do not have a significant impact on earnings since the revenue related to these energy sales generally offsets the cost of energy sold.
In the second quarter 2018, wholesale revenues from sales to affiliates were $14 million compared to $10 million for the corresponding period in 2017. The increase was primarily due to a 37.4% increase in KWH sales primarily resulting from increased generation to serve territorial load driven by the warm weather in June 2018.
For year-to-date 2018, wholesale revenues from sales to affiliates were $42 million compared to $47 million for the corresponding period in 2017. The decrease was primarily due to a 34.8% decrease in KWH sales primarily resulting from lower availability due to the first quarter 2018 planned outages at Gulf Power generating units. Partially offsetting this decrease was a 40.0% increase in the price of energy sold due to dispatching higher-priced generating resources driven by the colder weather in January 2018.
Fuel and Purchased Power Expenses
 Second Quarter 2018
vs.
Second Quarter 2017
 Year-to-Date 2018 vs. Year-to-Date 2017
 (change in millions) (% change) (change in millions) (% change)
Fuel$3
 3.4 $(23) (11.7)
Purchased power
  12
 15.4
Total fuel and purchased power expenses$3
   $(11)  
In the second quarter 2018, total fuel and purchased power expenses were $135 million compared to $132 million for the corresponding period in 2017. The increase was primarily the result of an $18 million increase related to the volume of KWHs generated and purchased, partially offset by a $15 million decrease related to the lower average cost of fuel and purchased power due to lower natural gas prices.
For year-to-date 2018, total fuel and purchased power expenses were $263 million compared to $274 million for the corresponding period in 2017. The decrease was primarily the result of a $20 million decrease related to the lower average cost of fuel and purchased power resulting from lower natural gas prices, partially offset by a $9 million net increase related to volume of KWHs generated and purchased.
Fuel and purchased power transactions do not have a significant impact on earnings since energy and capacity expenses are generally offset by energy and capacity revenues through Gulf Power's fuel and purchased power capacity cost recovery clauses and long-term wholesale contracts. See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses – Retail Fuel Cost Recovery" and " – Purchased Power Capacity Recovery" in Item 8 of the Form 10-K for additional information.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Details of Gulf Power's generation and purchased power were as follows:
 Second Quarter 2018 Second Quarter 2017 Year-to-Date 2018 Year-to-Date 2017
Total generation (in millions of KWHs)
2,235 1,898 4,011 4,220
Total purchased power (in millions of KWHs)
1,359 1,218 2,981 2,676
Sources of generation (percent) –
       
Coal56 50 48 52
Gas44 50 52 48
Cost of fuel, generated (in cents per net KWH) –
       
Coal3.21 3.17 3.18 3.23
Gas3.40 3.88 3.17 3.54
Average cost of fuel, generated (in cents per net KWH)
3.29 3.53 3.18 3.38
Average cost of purchased power (in cents per net KWH)(*)
4.56 5.37 4.56 4.93
(*)Average cost of purchased power includes fuel purchased by Gulf Power for tolling agreements where power is generated by the provider.
Fuel
In the second quarter 2018, fuel expense was $91 million compared to $88 million for the corresponding period in 2017. The increase was primarily due to a 17.8% increase in the volume of KWHs generated primarily to serve higher territorial load driven by the warm weather in June 2018.
For year-to-date 2018, fuel expense was $173 million compared to $196 million for the corresponding period in 2017. The decrease was primarily due to a 5.0% decrease in the volume of KWHs generated due to maintenance outages in 2018. Also contributing to the decrease was a 5.9% decrease in the average cost of fuel resulting from lower natural gas prices.
Purchased Power
In the second quarter 2018 and the corresponding period in 2017, purchased power expense was $44 million. The average cost of purchased power decreased 15.1% in the second quarter 2018 compared to the corresponding period in 2017 due to lower marginal natural gas prices, offset by an 11.6% increase in the volume of KWHs purchased due to higher territorial load.
For year-to-date 2018, purchased power expense was $90 million compared to $78 million for the corresponding period in 2017. The increase was primarily due to an 11.4% increase in the volume of KWHs purchased due to higher territorial load, partially offset by a 7.5% decrease in the average cost of purchased power due to lower natural gas prices.
Energy purchases from non-affiliates and affiliates will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's electric service territory, and the availability of the Southern Company system's generation. Affiliate purchases are made in accordance with the IIC or other contractual agreements, as approved by the FERC.

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Other Operations and Maintenance Expenses
Second Quarter 2018 vs. Second Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$—  $(10) (5.7)
In the second quarter 2018 and the corresponding period in 2017, other operations and maintenance expenses were $90 million. A decrease of $10 million in routine generation maintenance expenses was offset by a $10 million increase to the property damage reserve accrual.
For year-to-date 2018, other operations and maintenance expenses were $166 million compared to $176 million for the corresponding period in 2017. The decrease was primarily due to decreases of $11 million in routine generation maintenance expenses, including environmental expenditures, $4 million in energy service expenses, and $4 million in other operations and maintenance, primarily associated with vegetation management and employee benefits, partially offset by a $9 million increase to the property damage reserve accrual. See Note 1 to the financial statements of Gulf Power under "Property Damage Reserve" in Item 8 of the Form 10-K for additional information.
Expenses from energy services did not have a significant impact on earnings since they were generally offset by
associated revenues. Environmental compliance expenses did not have a significant impact on earnings since they were offset by environmental revenues through Gulf Power's environmental cost recovery clause. See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses – Environmental Cost Recovery" in Item 8 of the Form 10-K for additional information.
Depreciation and Amortization
Second Quarter 2018 vs. Second Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$13 37.1 $42 79.2
In the second quarter 2018, depreciation and amortization was $48 million compared to $35 million for the corresponding period in 2017. For year-to-date 2018, depreciation and amortization was $95 million compared to $53 million for the corresponding period in 2017. The increases were primarily due to depreciation credits of $8.5 million and $34 million recognized in the second quarter and year-to-date 2017, respectively, as authorized in a settlement agreement approved by the Florida PSC in 2013. See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Retail Base Rate Cases" in Item 8 of the Form 10-K for additional information.
Loss on Plant Scherer Unit 3
Second Quarter 2018 vs. Second Quarter 2017Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)(% change)(change in millions)(% change)
$—$(33)N/M
N/M - Not meaningful
In the first quarter 2017, Gulf Power recorded a $32.5 million write-down related to its ownership of Plant Scherer Unit 3 in accordance with the 2017 Gulf Power Rate Case Settlement Agreement. See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Retail Base Rate Cases" in Item 8 of the Form 10-K for additional information.

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Income Taxes (Benefit)
Second Quarter 2018 vs. Second Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(35) (145.8) $(35) (92.1)
In the second quarter 2018, income tax benefit was $11 million compared to tax expense of $24 million for the corresponding period in 2017. For year-to-date 2018, income taxes were $3 million compared to $38 million for the corresponding period in 2017. The changes were primarily due to the reduction in the federal income rate and the benefit from the flowback of excess deferred income taxes as a result of the Tax Reform Legislation as well as lower pre-tax earnings.
See Note (H) to the Condensed Financial Statements under "Effective Tax Rate" herein for additional information. Also see Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Retail Base Rate Cases" in Item 8 of the Form 10-K for more information regarding the 2017 Gulf Power Rate Case Settlement Agreement.
FUTURE EARNINGS POTENTIAL
The results of operations discussed above are not necessarily indicative of Gulf Power's future earnings potential. The level of Gulf Power's future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Gulf Power's business of providing electric service. These factors include Gulf Power's ability to maintain a constructive regulatory environment that continues to allow for the timely recovery of prudently-incurred costs during a time of increasing costs and limited projected demand growth over the next several years. Future earnings will be driven primarily by customer growth. Earnings will also depend upon maintaining and growing sales, considering, among other things, the adoption and/or penetration rates of increasingly energy-efficient technologies due to changes in the minimum allowable equipment efficiencies along with the continuation of changes in customer behavior, both of which could contribute to a net reduction in customer usage. Earnings are subject to a variety of other factors. These factors include weather, competition, energy conservation practiced by customers, the use of alternative energy sources by customers, the price of electricity, the price elasticity of demand, and the rate of economic growth or decline in Gulf Power's service territory. Demand for electricity is primarily driven by the pace of economic growth that may be affected by changes in regional and global economic conditions, which may impact future earnings. For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Gulf Power in Item 7 of the Form 10-K.
On May 20, 2018, Southern Company entered into a stock purchase agreement with NextEra Energy to sell all of the capital stock of Gulf Power for an aggregate cash purchase price of $5.75 billion (less the amount of indebtedness assumed at closing, which is currently estimated at approximately $1.4 billion), subject to (i) customary adjustments for indebtedness and working capital and (ii) reduction by the amount (if any) by which Gulf Power fails to meet a specified capital expenditure target. The completion of the sale is subject to the satisfaction or waiver of certain closing conditions, including, among others, (i) the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act, (ii) approval by the FERC and the Federal Communications Commission, (iii) the entry into certain ancillary agreements, including transmission-related agreements and a transition services agreement, among the parties and their affiliates, and (iv) other customary closing conditions. The sale is expected to occur in the first half of 2019. See Note (J) to the Condensed Financial Statements under "Southern Company's Sale of Gulf Power" herein for additional information. The ultimate outcome of this matter cannot be determined at this time.
Environmental Matters
Gulf Power's operations are regulated by state and federal environmental agencies through a variety of laws and regulations governing air, water, land, and protection of other natural resources. Gulf Power maintains comprehensive environmental compliance and greenhouse gas (GHG) strategies to assess upcoming requirements

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and compliance costs associated with these environmental laws and regulations. The costs, including capital expenditures and operations and maintenance costs, required to comply with environmental laws and regulations and to achieve stated goals may impact future unit retirement and replacement decisions, results of operations, cash flows, and financial condition. Related costs may result from the installation of additional environmental controls, closure and monitoring of CCR facilities, unit retirements, and adding or changing fuel sources for certain existing units, as well as related upgrades to the transmission system. A major portion of these costs are expected to be recovered through existing ratemaking provisions. The ultimate impact of environmental laws and regulations and the GHG goals discussed below will depend on various factors, such as state adoption and implementation of requirements, the availability and cost of any deployed control technology, and the outcome of pending and/or future legal challenges.
New or revised environmental laws and regulations could affect many areas of Gulf Power's operations. The impact of any such changes cannot be determined at this time. Environmental compliance costs could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis or through long-term wholesale agreements. The State of Florida has statutory provisions that allow a utility to petition the Florida PSC for recovery of prudent environmental compliance costs that are not being recovered through base rates or any other recovery mechanism. Gulf Power's current long-term wholesale agreements contain provisions that permit charging the customer with costs incurred as a result of changes in environmental laws and regulations. Further, increased costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively affect results of operations, cash flows, and financial condition. Additionally, many commercial and industrial customers may also be affected by existing and future environmental requirements, which for some may have the potential to ultimately affect their demand for electricity. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters," "Retail Regulatory Matters – Cost Recovery Clauses – Environmental Cost Recovery," and "Other Matters" of Gulf Power in Item 7 and Note 3 to the financial statements of Gulf Power under "Environmental Matters" in Item 8 of the Form 10-K for additional information, including a discussion on the State of Florida's statutory provisions on environmental cost recovery.
Environmental Laws and Regulations
Water Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Water Quality" of Gulf Power in Item 7 of the Form 10-K for additional information regarding the effluent limitations guidelines (ELG) rule.
On May 2, 2018, the EPA updated its anticipated final rulemaking schedule for ELG from September 2020 to December 2019. The impact of any changes to the ELG rule will depend on the content of the final rule and the outcome of any legal challenges and cannot be determined at this time.
Coal Combustion Residuals
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Coal Combustion Residuals" of Gulf Power in Item 7 of the Form 10-K for additional information regarding the Disposal of Coal Combustion Residuals from Electric Utilities rule (CCR Rule).
On July 30, 2018, the EPA published certain amendments to the CCR Rule, which will be effective August 29, 2018. These amendments extend the date from April 2019 to October 31, 2020 to cease sending CCR and other waste streams to impoundments that demonstrate compliance with all except two specified criteria. These amendments also establish groundwater protection standards for four constituents that do not have established EPA maximum contaminant levels and allow a participating state director or the EPA (where the EPA is the permitting authority) to suspend groundwater monitoring requirements under certain circumstances. Specific site impacts are being evaluated by Gulf Power.

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Georgia Power continues to perform engineering studies related to its plans to close the ash ponds at all of its generating plants, including Plant Scherer Unit 3 which is jointly owned with Gulf Power, in compliance with federal and state CCR rules. Georgia Power also continues to refine its closure strategy and cost estimates for each ash pond and is preparing permit applications as required by the State of Georgia CCR rule. While Gulf Power believes its recorded liability for ash pond closures appropriately reflects its obligations under the current closure strategy elected for Plant Scherer Unit 3, changes to such strategy and cost estimate would likely result in additional closure costs which would increase Gulf Power's ARO liability. It is not currently possible to determine the magnitude of an increase related to a change in closure strategy nor an increase related to ongoing engineering studies for the current closure strategy, and the timing of future cash outflows are indeterminable at this time. As permit applications advance, engineering studies continue, and the timing of the ash pond closure for Plant Scherer Unit 3 develops further during the second half of 2018 and in the future, Gulf Power will record any changes as necessary to its ARO liability, which could be material. Gulf Power expects to continue to periodically update these cost estimates as necessary, which could change further as additional information becomes available. See Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information.
Absent continued recovery of ARO costs through regulated rates, Gulf Power's results of operations, cash flows, and financial condition could be materially impacted. The ultimate outcome of these matters cannot be determined at this time.
Global Climate Issues
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues" of Gulf Power in Item 7 of the Form 10-K for additional information.
Through 2017, the Southern Company system has achieved an estimated GHG emission reduction of 36% since 2007. In April 2018, Southern Company established an intermediate goal of a 50% reduction in carbon emissions from 2007 levels by 2030 and a long-term goal of low- to no-carbon operations by 2050. To achieve these goals, the Southern Company system expects to continue growing its renewable energy portfolio, optimize technology advancements to modernize its transmission and distribution systems, increase the use of natural gas for generation, invest in energy efficiency, and continue research and development efforts focused on technologies to lower GHG emissions. The Southern Company system's ability to achieve these goals also will be dependent on many external factors, including supportive national energy policies, low natural gas prices, and the development, deployment, and advancement of relevant energy technologies. The ultimate outcome of this matter cannot be determined at this time.
FERC Matters
Market-Based Rate Authority
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "FERC Matters" of Gulf Power in Item 7 of the Form 10-K for additional information regarding proceedings related to the traditional electric operating companies' (including Gulf Power's) and Southern Power's 2014 and 2017 triennial market power analyses.
On May 4, 2018, the FERC issued an order terminating both proceedings, finding that the traditional electric operating companies (including Gulf Power) and Southern Power satisfy the FERC's standards for market-based rates. On May 9, 2018, the traditional electric operating companies (including Gulf Power) and Southern Power made the compliance filing required by the order. These proceedings are essentially concluded.
Open Access Transmission Tariff
On May 10, 2018, the Alabama Municipal Electric Authority and Cooperative Energy filed with the FERC a complaint against SCS and the traditional electric operating companies (including Gulf Power) claiming that the current 11.25% base ROE used in calculating the annual transmission revenue requirements of the traditional electric operating companies' (including Gulf Power's) open access transmission tariff is unjust and unreasonable as

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measured by the applicable FERC standards. The complaint requests that the base ROE be set no higher than 8.65% and that the FERC order refunds for the difference in revenue requirements that results from applying a just and reasonable ROE established in this proceeding upon determining the current ROE is unjust and unreasonable. On June 18, 2018, SCS and the traditional electric operating companies (including Gulf Power) filed their response challenging the adequacy of the showing presented by the complainants and offering support for the current ROE. The ultimate outcome of this matter cannot be determined at this time.
Retail Regulatory Matters
Gulf Power's rates and charges for service to retail customers are subject to the regulatory oversight of the Florida PSC. Gulf Power's rates are a combination of base rates and several separate cost recovery clauses for specific categories of costs. These separate cost recovery clauses address such items as fuel and purchased energy costs, purchased power capacity costs, energy conservation and demand side management programs, and the costs of compliance with environmental laws and regulations. Costs not addressed through one of the specific cost recovery clauses are recovered through base rates. See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information. The recovery balance of each regulatory clause for Gulf Power is reported in Note (B) to the Condensed Financial Statements herein.
Retail Base Rate Case
As a continuation of the 2017 Gulf Power Rate Case Settlement Agreement, on March 26, 2018, the Florida PSC approved the Gulf Power Tax Reform Settlement Agreement.
The Gulf Power Tax Reform Settlement Agreement results in annual reductions to Gulf Power's revenues of $18.2 million from base rates and $15.6 million from environmental cost recovery rates, implemented April 1, 2018, and also provides for a one-time refund of $69.4 million for the retail portion of unprotected (not subject to normalization) deferred tax liabilities through a reduced fuel cost recovery rate over the remainder of 2018. Through June 30, 2018, approximately $28 million of this refund has been reflected in customer bills. As a result of the Gulf Power Tax Reform Settlement Agreement, the Florida PSC also approved an increase in Gulf Power's maximum equity ratio from 52.5% to 53.5% for all retail regulatory purposes.
As part of the Gulf Power Tax Reform Settlement Agreement, a limited scope proceeding to address protected deferred tax liabilities consistent with IRS normalization principles was initiated on April 30, 2018. Pending resolution of this proceeding, Gulf Power is deferring the related amounts for 2018 as a regulatory liability. Through June 30, 2018, amounts deferred totaled $5 million. Unless otherwise agreed to by the parties to the Gulf Power Tax Reform Settlement Agreement, amounts recorded in this regulatory liability will be refunded to retail customers in 2019 through Gulf Power's fuel cost recovery rates. The ultimate outcome of this matter cannot be determined at this time.
See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Retail Base Rate Cases" in Item 8 of the Form 10-K for additional information.
Income Tax Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters" of Gulf Power in Item 7 of the Form 10-K and FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk," Note (B) to the Condensed Financial Statements under "Regulatory MattersGulf Power," and Note (H) to the Condensed Financial Statements herein for information regarding the Tax Reform Legislation and related regulatory actions.
Other Matters
Gulf Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Gulf Power is subject to certain claims and legal actions arising in the ordinary course of business. Gulf Power's business activities are subject to extensive governmental regulation related to public health and the environment, such as laws and regulations governing air, water, land, and protection of natural resources.

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Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental laws and regulations has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.
The ultimate outcome of such pending or potential litigation or regulatory matters cannot be predicted at this time; however, for current proceedings not specifically reported in Note (B) to the Condensed Financial Statements herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Gulf Power's financial statements. See Note (B) to the Condensed Financial Statements herein for a discussion of various other contingencies, regulatory matters, and other matters being litigated which may affect future earnings potential.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Gulf Power prepares its financial statements in accordance with GAAP. Significant accounting policies are described in Note 1 to the financial statements of Gulf Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Gulf Power's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Gulf Power in Item 7 of the Form 10-K for a complete discussion of Gulf Power's critical accounting policies and estimates.
Recently Issued Accounting Standards
See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Recently Issued Accounting Standards" of Gulf Power in Item 7 of the Form 10-K for additional information regarding ASU No. 2016-02, Leases (Topic 842). See Note (A) to the Condensed Financial Statements herein for information regarding Gulf Power's recently adopted accounting standards.
FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Gulf Power in Item 7 of the Form 10-K for additional information. Gulf Power's financial condition remained stable at June 30, 2018. Gulf Power intends to continue to monitor its access to short-term and long-term capital markets as well as bank credit agreements to meet future capital and liquidity needs. See "Capital Requirements and Contractual Obligations," "Sources of Capital," and "Financing Activities" herein for additional information.
Net cash provided from operating activities totaled $157 million for the first six months of 2018 compared to $124 million for the corresponding period in 2017. The $33 million increase was primarily due to increased fuel cost recovery. Net cash used for investing activities totaled $158 million in the first six months of 2018 primarily due to property additions. Net cash provided from financing activities totaled $4 million for the first six months of 2018 primarily due to an increase in notes payable and capital contributions from Southern Company, partially offset by the payment of common stock dividends. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first six months of 2018 include an increase of $60 million in property, plant, and equipment primarily due to additions at generation and distribution facilities; an increase of $54 million in other regulatory liabilities, current offset by a decrease of $74 million in deferred credits related to income taxes primarily as a result of the Gulf Power Tax Reform Settlement Agreement; and an increase of $45 million in notes payable related to commercial paper borrowings. See FUTURE EARNINGS POTENTIAL – "Retail Regulatory

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MattersRetail Base Rate Case" herein for additional information regarding the Gulf Power Tax Reform Settlement Agreement.
Capital Requirements and Contractual Obligations
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Gulf Power in Item 7 of the Form 10-K for a description of Gulf Power's capital requirements and contractual obligations. There are no scheduled maturities of long-term debt through June 30, 2019. See "Financing Activities" herein for additional information.
The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; storm impacts; changes in environmental laws and regulations; the outcome of any legal challenges to environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing generating units, to meet regulatory requirements; changes in the expected environmental compliance programs; changes in FERC rules and regulations; Florida PSC approvals; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.
Sources of Capital
Gulf Power plans to obtain the funds required to meet its future capital needs from sources similar to those used in the past, which were primarily from operating cash flows, external security issuances, borrowings from financial institutions, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon regulatory approval, prevailing market conditions, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Gulf Power in Item 7 of the Form 10-K for additional information.
At June 30, 2018, Gulf Power's current liabilities exceeded current assets by $29 million. Gulf Power's current liabilities may exceed current assets because of scheduled maturities of long-term debt and the periodic use of short-term debt as a funding source, as well as significant seasonal fluctuations in cash needs.
Gulf Power intends to utilize operating cash flows, external security issuances, and borrowings from financial institutions to fund its short-term capital needs. Gulf Power has substantial cash flow from operating activities and access to the capital markets and financial institutions to meet short-term liquidity needs.
At June 30, 2018, Gulf Power had approximately $31 million of cash and cash equivalents. Committed credit arrangements with banks at June 30, 2018 were as follows:
Expires     
Executable Term
Loans
 Expires Within One Year
2018 2019 2020 Total Unused 
One
Year
 
Term
Out
 
No Term
Out
(in millions)
$20
 $25
 $235
 $280
 $280
 $45
 $45
 $
See Note 6 to the financial statements of Gulf Power under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
Most of these bank credit arrangements contain covenants that limit debt levels and contain cross-acceleration provisions to other indebtedness (including guarantee obligations) of Gulf Power. Such cross-acceleration provisions to other indebtedness would trigger an event of default if Gulf Power defaulted on indebtedness, the payment of which was then accelerated. At June 30, 2018, Gulf Power was in compliance with all such covenants. A

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portion ($40 million) of the bank credit arrangements contain material adverse change clauses at the time of borrowings.
Subject to applicable market conditions, Gulf Power expects to renew or replace its bank credit arrangements, as needed, prior to expiration. In connection therewith, Gulf Power may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
Most of the unused credit arrangements with banks are allocated to provide liquidity support to Gulf Power's pollution control revenue bonds and commercial paper program. The amount of variable rate pollution control revenue bonds outstanding requiring liquidity support as of June 30, 2018 was approximately $82 million. In addition, at June 30, 2018, Gulf Power had approximately $37 million of fixed rate pollution control revenue bonds outstanding that were required to be remarketed within the next 12 months.
Gulf Power may also meet short-term cash needs through a Southern Company subsidiary organized to issue and sell commercial paper at the request and for the benefit of Gulf Power and the other traditional electric operating companies. Proceeds from such issuances for the benefit of Gulf Power are loaned directly to Gulf Power. The obligations of each traditional electric operating company under these arrangements are several and there is no cross-affiliate credit support. Short-term borrowings are included in notes payable on the balance sheets.
Details of short-term borrowings were as follows:
  
Short-term Debt
at June 30, 2018
 
Short-term Debt During the Period(*)
  
Amount
Outstanding
 
Weighted
Average
Interest
Rate
 
Average
Amount
Outstanding
 
Weighted
Average
Interest
Rate
 
Maximum
Amount
Outstanding
  (in millions)   (in millions)   (in millions)
Commercial paper $90
 2.4% $62
 2.3% $100
(*)Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 2018.
Gulf Power believes the need for working capital can be adequately met by utilizing the commercial paper program, lines of credit, short-term bank loans, and operating cash flows.
Credit Rating Risk
At June 30, 2018, Gulf Power did not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB- and/or Baa3 or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, and energy price risk management.
The maximum potential collateral requirements under these contracts at June 30, 2018 were as follows:
Credit Ratings
Maximum Potential
Collateral
Requirements
 (in millions)
At BBB- and/or Baa3$117
Below BBB- and/or Baa3$418
Included in these amounts are certain agreements that could require collateral in the event that Alabama Power or Georgia Power (affiliate companies of Gulf Power) has a credit rating change to below investment grade. Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating

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downgrade could impact the ability of Gulf Power to access capital markets and would be likely to impact the cost at which it does so.
On May 21, 2018, S&P revised its rating outlook for Gulf Power from negative to stable.
As a result of the Tax Reform Legislation, certain financial metrics, such as the funds from operations to debt percentage, used by the credit rating agencies to assess Southern Company and its subsidiaries, including Gulf Power, may be negatively impacted. The Gulf Power Tax Reform Settlement Agreement is expected to help mitigate these potential adverse impacts to Gulf Power's credit metrics by allowing a maximum equity ratio of 53.5% for all retail regulatory purposes. See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory MattersGulf Power" herein for additional information.
Financing Activities
Gulf Power did not issue or redeem any securities during the six months ended June 30, 2018.
In addition to any financings that may be necessary to meet capital requirements, contractual obligations, and storm recovery, Gulf Power plans to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.

MISSISSIPPI POWER COMPANY

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CONDENSED STATEMENTS OF OPERATIONS (UNAUDITED)
 
For the Three Months
Ended June 30,
 For the Six Months
Ended June 30,
For the Three Months
Ended March 31,
2018 2017 2018 20172019 2018
(in millions) (in millions)(in millions)
Operating Revenues:          
Retail revenues$212
 $222
 $406
 $422
$203
 $194
Wholesale revenues, non-affiliates55
 62
 118
 124
57
 68
Wholesale revenues, affiliates19
 15
 54
 20
22
 34
Other revenues11
 4
 20
 9
5
 6
Total operating revenues297
 303
 598
 575
287
 302
Operating Expenses:          
Fuel98
 102
 197
 180
93
 98
Purchased power7
 6
 16
 14
3
 9
Other operations and maintenance67
 72
 141
 148
59
 75
Depreciation and amortization44
 41
 84
 81
48
 41
Taxes other than income taxes27
 26
 54
 52
26
 28
Estimated loss on Kemper IGCC
 3,012
 45
 3,120
2
 44
Total operating expenses243
 3,259
 537
 3,595
231
 295
Operating Income (Loss)54
 (2,956) 61
 (3,020)56
 7
Other Income and (Expense):          
Allowance for equity funds used during construction
 36
 
 71
Interest expense, net of amounts capitalized(21) (17) (39) (37)(17) (19)
Other income (expense), net27
 3
 27
 5
5
 1
Total other income and (expense)6
 22
 (12) 39
(12) (18)
Earnings (Loss) Before Income Taxes60
 (2,934) 49
 (2,981)44
 (11)
Income taxes (benefit)13
 (881) 9
 (908)7
 (4)
Net Income (Loss)47
 (2,053) 40
 (2,073)$37
 $(7)
Dividends on Preferred Stock1
 1
 1
 1
Net Income (Loss) After Dividends on Preferred Stock$46
 $(2,054) $39
 $(2,074)
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (UNAUDITED)
For the Three Months
Ended June 30,
 For the Six Months
Ended June 30,
For the Three Months
Ended March 31,
2018 2017 2018 20172019 2018
(in millions) (in millions)(in millions)
Net Income (Loss)$47
 $(2,053) $40
 $(2,073)$37
 $(7)
Other comprehensive income (loss):
 
 
 

 
Qualifying hedges:          
Changes in fair value, net of tax of
$-, $-, $(1), and $-, respectively

 
 (1) 1
Reclassification adjustment for amounts included in net income,
net of tax of $-, $-, $-, and $-, respectively

 
 1
 
Changes in fair value, net of tax of $- and $(1), respectively
 (1)
Total other comprehensive income (loss)
 
 
 1

 (1)
Comprehensive Income (Loss)$47
 $(2,053) $40
 $(2,072)$37
 $(8)
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,
For the Three Months
Ended March 31,
2018 20172019 2018
(in millions)(in millions)
Operating Activities:      
Net income (loss)$40
 $(2,073)$37
 $(7)
Adjustments to reconcile net income (loss) to net cash provided from operating activities —   
Adjustments to reconcile net income (loss) to net cash used for operating activities —   
Depreciation and amortization, total86
 94
50
 44
Deferred income taxes289
 (860)(8) 155
Allowance for equity funds used during construction
 (71)
Estimated loss on Kemper IGCC28
 3,120
6
 37
Other, net(13) (11)(10) 3
Changes in certain current assets and liabilities —      
-Receivables(51) (15)11
 (129)
-Fossil fuel stock(2) 21
-Other current assets(9) (10)7
 (12)
-Accounts payable(15) (20)(38) (21)
-Accrued taxes(41) 
(62) (110)
-Accrued compensation(14) (17)(22) (22)
-Over recovered regulatory clause revenues10
 (30)
-Other current liabilities(11) 7
6
 
Net cash provided from operating activities297
 135
Net cash used for operating activities(23) (62)
Investing Activities:      
Property additions(74) (337)(45) (33)
Construction payables(9) (19)(8) (2)
Payments pursuant to LTSAs(13) 3
Other investing activities(12) (8)(10) (17)
Net cash used for investing activities(108) (361)(63) (52)
Financing Activities:      
Decrease in notes payable, net(4) (10)
 (4)
Proceeds —      
Senior notes600
 

 600
Short-term borrowings300
 4

 300
Capital contributions from parent company1
 1,001
Long-term debt to parent company
 40
Redemptions —   
Other long-term debt(900) (300)
Short-term borrowings(200) 
Long-term debt to parent company
 (591)
Pollution control revenue bonds43
 
Redemptions — Other long-term debt
 (900)
Return of capital(38) 
Other financing activities(6) (2)
 (5)
Net cash provided from (used for) financing activities(209) 142
5
 (9)
Net Change in Cash, Cash Equivalents, and Restricted Cash(20) (84)(81) (123)
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period248
 224
293
 248
Cash, Cash Equivalents, and Restricted Cash at End of Period$228
 $140
$212
 $125
Supplemental Cash Flow Information:      
Cash paid (received) during the period for —   
Interest (paid $39 and $53, net of $- and $27 capitalized for 2018
and 2017, respectively)
$39
 $26
Cash paid during the period for —   
Interest (net of $- and $- capitalized for 2019 and 2018, respectively)$13
 $21
Income taxes, net(257) (93)
 19
Noncash transactions — Accrued property additions at end of period23
 59
27
 30
The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.

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CONDENSED BALANCE SHEETS (UNAUDITED)
 
Assets At June 30, 2018 At December 31, 2017 At March 31, 2019 At December 31, 2018
 (in millions) (in millions)
Current Assets:        
Cash and cash equivalents $228
 $248
 $212
 $293
Receivables —        
Customer accounts receivable 37
 36
 29
 34
Unbilled revenues 42
 41
 37
 41
Income taxes receivable, current 37
 4
Affiliated 21
 16
 16
 21
Other accounts and notes receivable 24
 12
 36
 31
Fossil fuel stock 19
 17
 23
 20
Materials and supplies, current 50
 44
Other regulatory assets, current 121
 125
Materials and supplies 52
 53
Other regulatory assets 102
 116
Other current assets 9
 9
 6
 19
Total current assets 588
 552
 513
 628
Property, Plant, and Equipment:        
In service 4,816
 4,773
 4,821
 4,900
Less: Accumulated provision for depreciation 1,365
 1,325
 1,467
 1,429
Plant in service, net of depreciation 3,451
 3,448
 3,354
 3,471
Construction work in progress 88
 84
 110
 103
Total property, plant, and equipment 3,539
 3,532
 3,464
 3,574
Other Property and Investments 25
 30
 123
 24
Deferred Charges and Other Assets:        
Deferred charges related to income taxes 34
 35
 33
 33
Other regulatory assets, deferred 448
 437
 487
 474
Accumulated deferred income taxes 
 247
 148
 150
Other deferred charges and assets 19
 33
 17
 3
Total deferred charges and other assets 501
 752
 685
 660
Total Assets $4,653
 $4,866
 $4,785
 $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, 2018 At December 31, 2017 At March 31, 2019 At December 31, 2018
 (in millions) (in millions)
Current Liabilities:        
Securities due within one year $257
 $989
 $339
 $40
Notes payable 100
 4
Accounts payable —        
Affiliated 53
 59
 52
 60
Other 62
 96
 50
 90
Accrued taxes —    
Accrued income taxes 
 40
Other accrued taxes 51
 101
Accrued taxes 33
 95
Accrued interest 20
 15
Accrued compensation 25
 39
 16
 38
Accrued plant closure costs 42
 35
 26
 29
Asset retirement obligations, current 41
 37
Asset retirement obligations 28
 34
Over recovered regulatory clause liabilities 14
 14
Other current liabilities 74
 63
 55
 40
Total current liabilities 705
 1,463
 633
 455
Long-term Debt 1,522
 1,097
 1,280
 1,539
Deferred Credits and Other Liabilities:        
Accumulated deferred income taxes 60
 
 373
 378
Deferred credits related to income taxes 415
 372
 367
 382
Employee benefit obligations 112
 116
 111
 115
Asset retirement obligations, deferred 135
 137
 127
 126
Other cost of removal obligations 179
 178
 186
 185
Other regulatory liabilities, deferred 78
 79
 80
 81
Other deferred credits and liabilities 16
 33
 18
 16
Total deferred credits and other liabilities 995
 915
 1,262
 1,283
Total Liabilities 3,222
 3,475
 3,175
 3,277
Redeemable Preferred Stock 33
 33
Common Stockholder's Equity:    
Common stock, without par value —    
Authorized — 1,130,000 shares    
Outstanding — 1,121,000 shares 38
 38
Paid-in capital 4,531
 4,529
Accumulated deficit (3,166) (3,205)
Accumulated other comprehensive loss (5) (4)
Total common stockholder's equity 1,398
 1,358
Common Stockholder's Equity (See accompanying statements)
 1,610
 1,609
Total Liabilities and Stockholder's Equity $4,653
 $4,866
 $4,785
 $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, 20171
 $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, 20181
 $38
 $4,531
 $(3,213) $(5) $1,351
            
Balance at December 31, 20181
 $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, 20191
 $38
 $4,510
 $(2,934) $(4) $1,610
The accompanying notes as they relate to Mississippi Power are an integral part of these condensed financial statements.


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SECONDFIRST QUARTER 20182019 vs. SECONDFIRST QUARTER 2017
AND
YEAR-TO-DATE 2018 vs. YEAR-TO-DATE 2017


OVERVIEW
Mississippi Power operates as a vertically integrated utility providing electric service to retail customers within its traditional service territory located within the State of Mississippi and to wholesale customers in the Southeast.
Many factors affect the opportunities, challenges, and risks of Mississippi Power's business of providing electric service. These factors include Mississippi Power's ability to maintain and grow energy sales and 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 reliability, fuel, andprojected long-term demand growth, stringent environmental standards, as well as ongoingincluding 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 July 27, 2018,March 28, 2019, Mississippi Power andfiled a request with the Mississippi Public Utilities Staff (MPUS) entered intoFERC for a decrease in wholesale base revenues under the MRA tariff as agreed upon in a settlement agreement reached with respectits wholesale customers resolving all matters related to the 2018 PEP filing and all unresolved PEP filings for prior years (PEP Settlement Agreement), which wasKemper County energy facility similar to the retail rate settlement agreement approved by the Mississippi PSC on August 7, 2018. Rates underin February 2018 and reflecting the PEP Settlement Agreement, which result in approximately $21.6 million in additional revenue annually, will take effect forimpacts of the first billing cycle of September 2018.
On August 3, 2018, Mississippi Power and the MPUS entered into aTax Reform Legislation. The MRA settlement agreement to increaseprovides that base rates approximately $17will decrease $3.7 million annually, with respect to the 2018 ECO Plan filing (ECO Settlement Agreement), which was approved by the Mississippi PSC on August 7, 2018. Rates under the ECO Settlement Agreement will take effect for the first billing cycle of September 2018.
On May 8, 2018, the Mississippi PSC issued an order to begin an operations review of Mississippi Power in August 2018 with the final report expected by February 28,effective January 1, 2019. Mississippi Power expects that the review will include, but notmatter to be limited to, a comparative analysis of its costs, its cost recovery framework, and waysresolved in which it may streamline management operations for the reasonable benefit of ratepayers.second quarter 2019. The ultimate outcome of this matter cannot be determined at this time.
See FUTURE EARNINGS POTENTIAL – "Retail Regulatory Matters" herein for additional information.
As of June 30, 2018, Mississippi Power recorded charges to income of an immaterial amount for the second quarter 2018 and $45 million ($33 million after tax) for year-to-date 2018, primarily resulting from the abandonment and related closure activities for the mine and gasifier-related assets at the Kemper County energy facility. Additional closure costs for the mine and gasifier-related assets, currently estimated to cost up to $25 million pre-tax (excluding salvage, net of dismantlement costs), are expected to be incurred during the remainder of 2018 and 2019. In addition, period costs, including, but not limited to, costs for compliance and safety, ARO accretion, and property taxes for the mine and gasifier-related assets, are estimated at $4 million for the remainder of 2018, $7 million in 2019, and $4 million annually beginning in 2020. The ultimate outcome of this matter cannot be determined at this time.
On August 6, 2018, Mississippi Power filed its proposed Reserve Margin Plan (RMP), as required by the Mississippi PSC's order in the docket established for the purposes of pursuing a global settlement of the costs related to the Kemper County energy facility (Kemper Settlement Docket). Under the RMP, Mississippi Power proposes alternatives that would reduce its reserve margin, with the most economic of the alternatives being the 2-year and 7-year acceleration of the retirement of Plant Watson Units 4 and 5, respectively, to the first quarter 2022 and the 4-year acceleration of the retirement of Plant Greene County Units 1 andNote 2 to the third quarter 2021 and the third quarter 2022, respectively, in order to lower or avoid operating costs. The Plant Greene County unit retirements would require the completion by Alabama Power of proposed transmission and system reliability

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improvements, as well as agreement by Alabama Power. The RMP filing also states that, in the event the Mississippi PSC ultimately approves an alternative that includes an accelerated retirement, Mississippi Power would require authorization to defer in a regulatory asset for future recovery the remaining net book value of the units at the time of retirement. Mississippi Power expects the MPUS and other interested parties to review the proposal prior to resolution by the Mississippi PSC. The ultimate outcome of this matter cannot be determined at this time. However, if approved by the Mississippi PSC, the alternatives are not expected to have any adverse impact on customer rates.
For additional information on the Kemper County energy facility, see Note 3 to the financial statements of Mississippi Power under "Kemper County Energy Facility""FERC Matters" in Item 8 of the Form 10-K and FUTURE EARNINGS POTENTIAL – "Kemper County Energy Facility" and Note (B) to the Condensed Financial Statements under "Kemper County Energy Facility" herein.
In March 2018, Mississippi Power issued $300 million aggregate principal amount of Series 2018A Floating Rate Senior Notes due March 27, 2020 bearing interest based on three-month LIBOR and $300 million aggregate principal amount of Series 2018B 3.95% Senior Notes due March 30, 2028. In March 2018, Mississippi Power also entered into a $300 million short-term floating rate bank loan bearing interest based on one-month LIBOR, of which $200 million was repaid in the second quarter 2018 and $50 million was repaid on July 31, 2018. Mississippi Power used the proceeds from these financings to repay a $900 million unsecured term loan.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 after dividends on preferred stock.income.
RESULTS OF OPERATIONS
Net Income (Loss)
Second Quarter 2018 vs. Second Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$2,100 N/M $2,113 N/M
First Quarter 2019 vs. First Quarter 2018
(change in millions)(% change)
$44N/M
N/M - Not meaningful
Mississippi Power's net income after dividends on preferred stock for the secondfirst quarter 20182019 was $46$37 million compared to a loss of $2.05 billion$7 million for the corresponding period in 2017. Mississippi Power's2018. The increase in net income after dividends on preferred stock for year-to-date 2018 was $39 million comparedis primarily attributable to a loss of $2.07 billion for the corresponding period in 2017. The changes were related to lower pre-tax charges associated with the Kemper IGCC slightly offset by the cessation of AFUDC equity related to the Kemper IGCCand a decrease in the second quarter 2017.
See Note 3 to the financial statements of Mississippi Power under "Kemper County Energy Facility" in Item 8 of the Form 10-Koperations and Note (B) to the Condensed Financial Statements under "Kemper County Energy Facility" herein for additional information.
Retail Revenues
Second Quarter 2018 vs. Second Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(10) (4.5) $(16) (3.8)
In the second quarter 2018, retail revenues were $212 million compared to $222 million for the corresponding period in 2017. For year-to-date 2018, retail revenues were $406 million compared to $422 million for the corresponding period in 2017.maintenance expenses.

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Retail Revenues
First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change)
$9 4.6
In the first quarter 2019, retail revenues were $203 million compared to $194 million for the corresponding period in 2018.
Details of the changes in retail revenues were as follows:
Second Quarter 2018 Year-to-Date 2018First Quarter 2019
(in millions) (% change) (in millions) (% change)(in millions) (% change)
Retail – prior year$222
   $422
  $194
  
Estimated change resulting from –          
Rates and pricing(7) (3.2) (14) (3.3)15
 7.7 %
Sales decline(2) (0.8) (2) (0.5)
Sales growth1
 0.5
Weather4
 1.8
 10
 2.4
(9) (4.6)
Fuel and other cost recovery(5) (2.3) (10) (2.4)2
 1.0
Retail – current year$212
 (4.5)% $406
 (3.8)%$203
 4.6 %
Revenues associated with changes in rates and pricing decreasedincreased in the secondfirst quarter and year-to-date 20182019 when compared to the corresponding periodsperiod in 20172018 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 reduction in base ratesrate decrease related to the Kemper County energy facility that became effective for the first billing cycle of April 2018 of $5 million and $6 million, respectively, and decreases of $2 million and $8 million, respectively, due to ECO Plan rates implemented in the second quarter 2017 related to the Plant Daniel Units 1 and 2 scrubbers.a new tolling arrangement accounted for as a sales-type lease. See Note 32 to the financial statements of Mississippiunder "Mississippi Power under "Retail Regulatory Matters– Performance Evaluation Plan," " – Environmental Compliance Overview Plan"Plan," and "Kemper" – 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 forincreased in the secondfirst quarter and year-to-date 20182019 compared to the corresponding periodsperiod in 2017.2018. Weather-adjusted residential KWH sales were relatively flatincreased 1.5% in the secondfirst quarter and year-to-date 2018.2019 due to increased customer usage. Weather-adjusted commercial KWH sales decreased 2.8% and 1.6% for the second quarter and year-to-date 2018, respectively,3.4% due to decreased customer usage. Industrial KWH sales decreased 3.9% primarily due to decreased customer usage related to energy efficiency, slightly offset by customer growth. Industrial KWH sales decreased 2.0% and 0.4% for the second quarter and year-to-date 2018, respectively, primarily due to decreased usage by several large industrial customers relatedcustomers.
Revenues associated with weather decreased in the first quarter 2019 compared to energy efficiency and optimization efforts.the corresponding period in 2018 primarily due to milder weather.
Fuel and other cost recovery revenues decreasedincreased in the secondfirst quarter and year-to-date 20182019 when compared to the corresponding periodsperiod in 20172018 primarily as a result of lowerhigher recoverable fuel costs. Recoverable fuel costs include fuel and purchased power expenses reduced by the fuel portion of wholesale revenues from energy sold to customers outside Mississippi Power's service territory. Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the energy component of purchased power costs, and do not affect net income.
Wholesale Revenues – Non-Affiliates
Second Quarter 2018 vs. Second Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(7) (11.3) $(6) (4.8)
First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change)
$(11) (16.2)
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

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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""FERC Matters" herein for additional information.

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In the secondfirst quarter 2018,2019, wholesale revenues from sales to non-affiliates were $55$57 million compared to $62$68 million for the corresponding period in 2017. For year-to-date 2018, wholesale revenues from sales to non-affiliates were $118 million compared to $124 million for the corresponding period in 2017. In the second quarter and year-to-date 2018, the decreases2018. This decrease primarily resulted from a $6 million decrease due to lower market-based contract capacity and energy sales and fewer opportunity sales and a $5 million decrease in revenue under the Shared Services Agreement (SSA) of $5 millioncost-based electric tariff revenues due to decreased customer usage and $9 million, respectively, as a result of transmission revenue now being recovered under the Open Access Transmission Tariff (OATT). The year-to-date 2018 decrease was partially offset by an increase in sales due tomilder weather.
Wholesale Revenues – Affiliates
Second Quarter 2018 vs. Second Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$4 26.7 $34 N/M
N/M - Not meaningful
First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change)
$(12) (35.3)
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 secondfirst quarter 2018,2019, wholesale revenues from sales to affiliates were $19$22 million compared to $15$34 million for the corresponding period in 2017. For year-to-date 2018, wholesale revenues from sales to affiliates were $54 million compared to $20 million for the corresponding period in 2017. These increases were2018. This decrease was primarily due to increases ina $19 million decrease associated with lower natural gas prices, partially offset by a $7 million increase associated with higher KWH sales due to increased availabilitythe dispatch of Mississippi Power's lower cost generation resources to serve the Southern Company system's territorial load in 2018 as compared to 2017.
Other Revenues
Second Quarter 2018 vs. Second Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$7 N/M $11 N/M
N/M - Not meaningful
In the second quarter 2018, other revenues were $11 million compared to $4 million for the corresponding period in 2017. For year-to-date 2018, other revenues were $20 million compared to $9 million for the corresponding period in 2017. These increases were primarily due to increases in transmission revenue related to SSA customers now being recovered under the OATT.load.
Fuel and Purchased Power Expenses
Second Quarter 2018
vs.
Second Quarter 2017
 Year-to-Date 2018 vs. Year-to-Date 2017First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change) (change in millions) (% change)(change in millions) (% change)
Fuel$(4) (3.9) $17
 9.4$(5) (5.1)
Purchased power1
 16.7 2
 14.3(6) (66.7)
Total fuel and purchased power expenses$(3) $19
 $(11) 
In the secondfirst quarter 2018,2019, total fuel and purchased power expenses were $105$96 million compared to $108$107 million for the corresponding period in 2017.2018. The decrease was primarily due to a $13 million decrease in the cost of

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natural gas and purchased power, partially offset by a $10 million increase in the volume of KWHs generated and purchased.
For year-to-date 2018, total fuel and purchased power expenses were $213 million compared to $194 million for the corresponding period in 2017. The increase was primarily due to a $28 million increase in the volume of KWHs generated and purchased, partially offset by a $10 million decrease in the costlower average costs of natural gas and purchased power.
Fuel and purchased power energy transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues through Mississippi Power's fuel cost recovery clause.

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Details of Mississippi Power's generation and purchased power were as follows:
Second Quarter 2018 Second Quarter 2017 Year-to-Date 2018 Year-to-Date 2017First Quarter 2019 First Quarter 2018
Total generation (in millions of KWHs)
4,081 3,927 8,084 7,0883,950 4,003
Total purchased power (in millions of KWHs)(*)
238 121 433 362
Total purchased power (in millions of KWHs)
207 194
Sources of generation (percent)
      
Coal7 7 6 84 4
Gas93 93 94 9296 96
Cost of fuel, generated (in cents per net KWH)
  
Coal3.42 3.61 3.49 3.464.42 3.62
Gas2.51 2.73 2.56 2.692.46 2.60
Average cost of fuel, generated (in cents per net KWH)
2.58 2.79 2.61 2.762.53 2.65
Average cost of purchased power (in cents per net KWH)(*)
2.86 4.74 3.71 3.80
Average cost of purchased power (in cents per net KWH)
1.62 4.74
(*)Includes energy produced during the test period for the Kemper IGCC, which is accounted for in accordance with FERC guidance.
Fuel
In the secondfirst quarter 2018, total2019, fuel expense was $98$93 million compared to $102$98 million for the corresponding period in 2017.2018. The decrease was primarily due to an 8.0%a 5.6% decrease in the cost of natural gas, partially offset by an increase in non-territorial sales as a result of lower prices.
For year-to-date 2018, total fuel expense was $197 million compared to $180 million for the corresponding period in 2017. The increase was due to a 14.9% increase in the volume of KWHs generated primarily as a result of higher sales, partially offset by a 5.0% decrease in theaverage cost of natural gas.
Purchased Power
In the first quarter 2019, purchased power expense was $3 million compared to $9 million for the corresponding period in 2018. The decrease was primarily due to a 66% decrease in the average cost per KWH purchased as a result of colder weather in the first quarter 2018 as compared to the corresponding period in 2019.
Energy purchases will vary depending on the market prices of wholesale energy as compared to the cost of the Southern Company system's generation, demand for energy within the Southern Company system's service territory, and the availability of the Southern Company system's generation. These purchases are made in accordance with the IIC or other contractual agreements, as approved by the FERC.
Other Operations and Maintenance Expenses
Second Quarter 2018 vs. Second Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(5) (6.9) $(7) (4.7)
First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change)
$(16) (21.3)
In the secondfirst quarter 2018,2019, other operations and maintenance expenses were $67$59 million compared to $72$75 million for the corresponding period in 2017. For year-to date 2018, other operations2018. The decrease was primarily due to decreases of $9 million in generation planned outage expenses and maintenance$4 million in employee compensation and benefit expenses were $141related to an employee attrition plan recorded in 2018.
Depreciation and Amortization
First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change)
$7 17.1
In the first quarter 2019, depreciation and amortization was $48 million compared to $148$41 million for the corresponding period in 2017. These decreases were2018. The increase was primarily duerelated to a$6 million of amortization associated with ECO

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reduction in professional services relatedPlan regulatory assets. See Note 2 to the combined cycle and associated common facilities portionfinancial statements under "Mississippi Power – Environmental Compliance Overview Plan" in Item 8 of the Kemper County energy facility.
Depreciation and Amortization
Second Quarter 2018 vs. Second Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$3 7.3 $3 3.7
In the second quarter 2018, depreciation and amortization was $44 million compared to $41 million for the corresponding period in 2017. The increase was primarily related to $4 million of depreciationForm 10-K for additional plant in service, partially offset by a $2 million decrease in amortization associated with regulatory assets and liabilities.information.
For year-to-date 2018, depreciation and amortization was $84 million compared to $81 million for the corresponding period in 2017. The increase was primarily related to $7 million of depreciation for additional plant in service, partially offset by a $4 million decrease in amortization associated with regulatory assets and liabilities.
Estimated Loss on Kemper IGCC
Second Quarter 2018 vs. Second Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(3,012) (100.0) $(3,075) (98.6)
First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change)
$(42) (95.5)
EstimatedIn the first quarter 2019, estimated losses on the Kemper IGCC were immaterial$2 million compared to $44 million for the second quarter 2018 and $45 million for year-to-datecorresponding period in 2018, resulting from thelower charges related to abandonment and related closure activities for the mine and gasifier-related assets recorded in 2019 as compared to $3.01 billion and $3.12 billion for the corresponding periodsperiod in 2017 related to revisions to the estimated construction costs for, and subsequent suspension of, the Kemper IGCC in June 2017.2018.
See Note 32 to the financial statements of Mississippiunder "Mississippi Power under "Kemper– Kemper County Energy Facility" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Kemper"Mississippi PowerKemper County Energy Facility"Facility" herein for additional information.
Allowance for Equity Funds Used During ConstructionOther Income (Expense), Net
Second Quarter 2018 vs. Second Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(36) (100.0) $(71) (100.0)
First Quarter 2019 vs. First Quarter 2018
(change in millions)(% change)
$4N/M
N/M - Not meaningful
In the secondfirst quarter and year-to-date 2018, AFUDC equity2019, other income (expense), net was immaterial compared to $36 million and $71 million, respectively, recorded for the corresponding periods in 2017 related to the Kemper IGCC construction. These decreases resulted from suspension of the Kemper IGCC construction in June 2017.
See Note 3 to the financial statements of Mississippi Power under "Kemper County Energy Facility" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Kemper County Energy Facility" herein for additional information.
Interest Expense, Net of Amounts Capitalized
Second Quarter 2018 vs. Second Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$4 23.5 $2 5.4
In the second quarter 2018, interest expense, net of amounts capitalized was $21$5 million compared to $17$1 million for the corresponding period in 2017. For year-to-date 2018, interest expense, net of amounts capitalized2018. The increase was $39

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million compared to $37 million for the corresponding period in 2017. These increases were primarily due to reductions in AFUDC debt of $12 million and $24 million in the second quarter and year-to-date 2018, respectively, related to the Kemper IGCC project suspension in June 2017, largely offset by decreases inhigher interest expenseincome associated with a new tolling arrangement accounted for as a result of a decrease in average outstanding debt, the reversal of tax reserves in 2017, and decreases due to the completion of Kemper IGCC carrying cost amortization in 2017.
lease. See Note 3 to the financial statements of Mississippi Power under "Kemper County Energy Facility" in Item 8 of the Form 10-K and Note (H)(L) to the Condensed Financial Statements herein for additional information.
Other Income (Expense)
Second Quarter 2018 vs. Second Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$24 N/M $22 N/M
N/M - Not Meaningful
In the second quarter 2018, other income (expense), net was $27 million compared to $3 million for the corresponding period in 2017. For year-to-date 2018, other income (expense), net was $27 million compared to $5 million for the corresponding period in 2017. These increases were primarily due to the settlement of Mississippi Power's Deepwater Horizon claim in May 2018.
See Note (B) to the Condensed Financial Statements under "General Litigation Matters" herein.
Income Taxes (Benefit)
Second Quarter 2018 vs. Second Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$894 N/M $917 N/M
N/M - Not Meaningful
First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change)
$11 275.0
In the secondfirst quarter 2018,2019, income taxes were $13$7 million compared to an income tax benefit of $881$4 million for the corresponding period in 2017. For year-to-date 2018, income taxes were $9 million compared2018. This change was primarily due to an income tax benefit of $908 million for the corresponding period in 2017. These changes werehigher pre-tax earnings primarily due to lower estimated losses on the Kemper IGCC, net of the related non-deductible AFUDC equity in 2018 due to the Kemper IGCC project suspension in 2017. These increases also reflect increases resulting from higher pre-tax earnings, partially offset by an increase in the 2017 reversalflowback of tax reserves related to research and experimental deductions andexcess deferred income taxes as a result of a settlement agreement reached with wholesale customers under the impact of the Tax Reform Legislation.
MRA tariff. See Note (H)(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 limited projected demand growth over the next several years. Another factor is Mississippi Power'sits ability to prevail against legal challenges associated with the Kemper County energy facility. Future earnings will be driven primarily by continued customer growth.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

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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.
For additional information relating to these issues, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL of Mississippi Power in Item 7 of the Form 10-K.
Environmental Matters
Mississippi Power's operations are regulated by state and federal environmental agencies through a variety of laws and regulations governing air, water, land, and protection of other natural resources. Mississippi Power maintains comprehensive environmental compliance and greenhouse gas (GHG)GHG strategies to assess upcoming requirements and compliance costs associated with these environmental laws and regulations. The costs, including capital expenditures, and operations and maintenance costs, and costs reflected in ARO liabilities, required to comply with environmental laws and regulations and to achieve stated goals may impact future electric generating unit retirement and replacement decisions, results of operations, cash flows, andand/or financial condition. Related costs may result from the installation of additional environmental controls, closure and monitoring of CCR facilities, unit retirements, and adding or changing fuel sources for certain existing units, as well as related upgrades to theMississippi Power's transmission system.and distribution systems. A major portion of these costs areis expected to be recovered through existing ratemaking provisions.retail and wholesale rates. The ultimate impact of environmental laws and regulations and the GHG goals discussed below will depend on various factors, such as state adoption and implementation of requirements, the availability and cost of any deployed control technology, 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 fully recovered in rates on a timely basis or through long-term wholesale agreements. Further, increased costs that are recovered through regulated rates could contribute to reduced demand for electricity, which could negatively affect results of operations, cash flows, andand/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 of Mississippi Power under "Environmental Matters" in Item 8 of the Form 10-K for additional information.
Environmental Laws and Regulations
Water QualityFERC Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Water Quality" of Mississippi PowerNote 2 to the financial statements under "FERC Matters" in Item 78 of the Form 10-K for additional information regarding the effluent limitations guidelines (ELG) rule.information.
Municipal and Rural Association Tariff
On May 2,March 28, 2019, Mississippi Power filed a request with the FERC 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 EPA updated its anticipated final rulemaking schedule for ELG from September 2020impacts of the Tax Reform Legislation. The MRA settlement agreement provides that base rates will decrease $3.7 million annually, effective January 1, 2019. Mississippi Power expects the matter to Decemberbe resolved in the second quarter 2019. The impact of any changes to the ELG rule will depend on the content of the final rule and theultimate outcome of any legal challenges andthis matter cannot be determined at this time.
Coal Combustion ResidualsOpen Access Transmission Tariff
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental LawsOn March 25, 2019, the Alabama Municipal Electric Authority and Regulations – Coal Combustion Residuals" ofCooperative Energy and SCS and the traditional electric operating companies (including Mississippi Power in Item 7 ofPower) filed a formal settlement agreement with the Form 10-K for additional information regarding the Disposal of Coal Combustion Residuals from Electric Utilities rule (CCR Rule).FERC

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On July 30,agreeing to a rate reduction based on a 10.6% ROE, with a retroactive effective date of May 10, 2018, the EPA published certain amendmentsand a five-year moratorium on these parties seeking changes to the CCR Rule, which will be effective August 29, 2018. These amendments extend the date from April 2019 to October 31, 2020 to cease sending CCR and other waste streams to impoundments that demonstrate compliance with all except two specified criteria. These amendments also establish groundwater protection standards for four constituents that do not have established EPA maximum contaminant levels and allow a participating state director or the EPA (where the EPA is the permitting authority) to suspend groundwater monitoring requirements under certain circumstances. Specific site impacts are being evaluated by Mississippi Power.
In June 2018, Mississippi Power recorded an increase of approximately $14 million to its AROs related to the CCR Rule. Approximately $11 million of the revised cost estimates as of June 30, 2018 are based on information from feasibility studies performed on an ash pond at a plant that is co-owned with Alabama Power. These studies indicated that additional closure costs, primarily related to increases in estimated ash volume, water management requirements, and design revisions, will be required to close the ash pond under the planned closure-in-place methodology. As further analysis is performed and closure details are developed, Mississippi Power expects to periodically update these cost estimates as necessary. See Note (A) to the Condensed Financial Statements under "Asset Retirement Obligations" herein for additional information.
Absent continued recovery of ARO costs through regulated rates, Mississippi Power's results of operations, cash flows, and financial condition could be materially impacted. The ultimate outcome of these matters cannot be determined at this time.
Global Climate Issues
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Global Climate Issues" of Mississippi Power in Item 7 of the Form 10-K for additional information.
Through 2017, the Southern Company system has achieved an estimated GHG emission reduction of 36% since 2007. In April 2018, Southern Company established an intermediate goal of a 50% reduction in carbon emissions from 2007 levels by 2030 and a long-term goal of low- to no-carbon operations by 2050. To achieve these goals, the Southern Company system expects to continue growing its renewable energy portfolio, optimize technology advancements to modernize its transmission and distribution systems, increase the use of natural gas for generation, invest in energy efficiency, and continue research and development efforts focused on technologies to lower GHG emissions. The Southern Company system's ability to achieve these goals also will be dependent on many external factors, including supportive national energy policies, low natural gas prices, and the development, deployment, and advancement of relevant energy technologies.OATT formula rate. The ultimate outcome of this matter cannot be determined at this time.
time; however, if approved by the FERC Matters
Municipal and Rural Association Tariff
See Note 3 toas filed, the OATT settlement would not have a material impact on the financial statements of Mississippi Power under "FERC Matters – Municipal and Rural Associations Tariff" in Item 8 of the Form 10-K for additional information.
Mississippi Power expects to make an MRA filing in 2018. The ultimate outcome of this matter cannot be determined at this time.
Fuel Cost Recovery
Mississippi Power has a wholesale MRA and a Market Based (MB) fuel cost recovery factor. At June 30, 2018, the amount of over-recovered wholesale MRA fuel costs included in other regulatory liabilities, current on the condensed balance sheet was approximately $5 million compared to an immaterial amount at December 31, 2017. Under-recovered wholesale MB fuel costs included in the balance sheets were immaterial at June 30, 2018 and December 31, 2017.

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See Note 3 to the financial statements of Mississippi Power under "FERC Matters – Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information.
Market-Based Rate Authority
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "FERC Matters Market-Based Rate Authority" of Mississippi Power in Item 7 of the Form 10-K for additional information regarding proceedings related to the traditional electric operating companies' (including Mississippi Power's) and Southern Power's 2014 and 2017 triennial market power analyses.
On May 4, 2018, the FERC issued an order terminating both proceedings, finding that the traditional electric operating companies (including Mississippi Power) and Southern Power satisfy the FERC's standards for market-based rates. On May 9, 2018, the traditional electric operating companies (including Mississippi Power) and Southern Power made the compliance filing required by the order. These proceedings are essentially concluded.
Cooperative Energy Power Supply Agreement
See Note 3 to the financial statements of Mississippi Power under "FERC Matters – Cooperative Energy Power Supply Agreement" in Item 8 of the Form 10-K for additional information regarding Cooperative Energy's network integration transmission service agreement (NITSA) with SCS.
On March 23, 2018, the FERC accepted the amendment to the NITSA between Cooperative Energy and SCS, effective April 1, 2018.
Open Access Transmission Tariff
On May 10, 2018, the Alabama Municipal Electric Authority and Cooperative Energy filed with the FERC a complaint against SCS and the traditional electric operating companies (including Mississippi Power) claiming that the current 11.25% base ROE used in calculating the annual transmission revenue requirements of the traditional electric operating companies' (including Mississippi Power's) open access transmission tariff is unjust and unreasonable as measured by the applicable FERC standards. The complaint requests that the base ROE be set no higher than 8.65% and that the FERC order refunds for the difference in revenue requirements that results from applying a just and reasonable ROE established in this proceeding upon determining the current ROE is unjust and unreasonable. On June 18, 2018, SCS and the traditional electric operating companies (including Mississippi Power) filed their response challenging the adequacy of the showing presented by the complainants and offering support for the current ROE. The ultimate outcome of this matter cannot be determined at this time.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.
On May 8, 2018, the Mississippi PSC issued an order to begin an operations review of Mississippi Power is scheduled to file a base rate case in August 2018 with the final report expected by February 28,fourth quarter 2019. Mississippi Power expects that the review will include, but not be limited to, a comparative analysis of its costs, its cost recovery framework, and ways in which it may streamline management operations for the reasonable benefit of ratepayers. The ultimate outcome of this matter cannot be determined at this time.
See Note 32 to the financial statements of Mississippi Power under "Retail Regulatory Matters" and "Kemper County Energy Facility""Mississippi Power" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory MattersMississippi Power" herein for additional information.

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Performance Evaluation Plan
On February 7, 2018, Mississippi Power submitted its revised 2018 projected PEP filing to the Mississippi PSC, which reflected the impacts of the Tax Reform Legislation, requesting an increase in annual retail revenues of $26 million based on a performance adjusted ROE of 9.33% and an increased equity ratio of 55%.
On March 22, 2018, Mississippi Power submitted its annual PEP lookback filing for 2017, which reflected no surcharge or refund.
On July 27, 2018, Mississippi Power and the MPUS entered into the PEP Settlement Agreement, which was approved by the Mississippi PSC on August 7, 2018. Rates under the PEP Settlement Agreement will take effect for the first billing cycle of September 2018.
The PEP Settlement Agreement provides for an increase of approximately $21.6 million in annual base retail revenues, which excludes approximately $5.5 million requested for certain compensation costs contested by the MPUS. Under the PEP Settlement Agreement, Mississippi Power expects to defer these costs for 2018 and 2019 as a regulatory asset. The Mississippi PSC is currently expected to rule on the appropriate treatment for such costs in connection with Mississippi Power's next base rate case, which is scheduled to be filed in the fourth quarter 2019 (2019 Base Rate Case). The ultimate outcome of this matter cannot be determined at this time.
Pursuant to the PEP Settlement Agreement, Mississippi Power's performance-adjusted allowed ROE will be 9.31% and its allowed equity ratio will remain at 50%, pending further review by the Mississippi PSC. In lieu of the requested equity ratio increase, Mississippi Power will retain $44 million of excess accumulated deferred income taxes resulting from the Tax Reform Legislation, which had been proposed to be amortized beginning in 2018, until the conclusion of the 2019 Base Rate Case. Further, Mississippi Power will seek equity contributions sufficient to restore its equity ratio (which was 43.5% at June 30, 2018) to the 50% target. In the event Mississippi Power's actual average equity ratio for 2018 is more than 1% higher or lower than the 50% target, Mississippi Power will defer the corresponding difference in its revenue requirement as a regulatory asset or liability for resolution in the 2019 Base Rate Case.
Pursuant to the PEP Settlement Agreement, PEP proceedings will be suspended until after the conclusion of the 2019 Base Rate Case and Mississippi Power will not be required to make any PEP filings for regulatory years 2018, 2019, and 2020. The PEP Settlement Agreement also resolves all open PEP filings with no change to customer rates. As a result, in the third quarter 2018, Mississippi Power expects to recognize revenues of $5 million previously reserved in connection with the 2012 PEP lookback filing.
Energy Efficiency
On May 8, 2018, the Mississippi PSC issued an order approving Mississippi Power's revised annual projected Energy Efficiency Cost Rider 2018 compliance filing, submitted on May 3, 2018, which increased annual retail revenues by approximately $3 million effective with the first billing cycle for June 2018.
Environmental Compliance Overview Plan
On August 3, 2018, Mississippi Power and the MPUS entered into the ECO Settlement Agreement, which provides for an increase of approximately $17 million in annual base retail revenues and was approved by the Mississippi PSC on August 7, 2018. Rates under the ECO Settlement Agreement will take effect for the first billing cycle of September 2018 and will continue in effect until modified by the Mississippi PSC. These revenues are expected to be sufficient to recover the costs included in Mississippi Power's request for 2018, as well as the remaining deferred amounts that were originally expected to be recovered in 2019. In accordance with the ECO Settlement Agreement, ECO Plan proceedings will be suspended until after the conclusion of the 2019 Base Rate Case and Mississippi Power will not be required to make any ECO Plan filings for 2018, 2019, and 2020, with any necessary true-ups to be reflected in the 2019 Base Rate Case. The ECO Settlement Agreement contains the same terms as the PEP Settlement Agreement described herein with respect to allowed ROE and equity ratio.

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Ad Valorem Tax Adjustment
On May 8, 2018, the Mississippi PSC approved Mississippi Power's annual ad valorem tax adjustment factor filing for 2018, which included an annual rate increase of 0.8%, or $7 million, in annual retail revenues effective with the first billing cycle for June 2018, primarily due to increased assessments.
Kemper County Energy Facility
For additional information on the Kemper County energy facility, seeSee Note 32 to the financial statements of Mississippiunder "Mississippi Power under "Kemper– Kemper County Energy Facility" in Item 8 of the Form 10-K.10-K for additional information.
As the mining permit holder, for the Kemper County energy facility, Liberty Fuels Company, LLC has a legal obligation to perform mine reclamation, and Mississippi Power has a contractual obligation to fund all reclamation activities. MineAs a result of the abandonment of the Kemper IGCC, final mine reclamation began in the first quarter 2018.2018 and is expected to be substantially completed in 2020, with monitoring expected to continue through 2027. See Note 16 to the financial statements of Mississippi Power under "Variable Interest Entities" in Item 8 of the Form 10-K for additional information.
As of June 30, 2018,During the first quarter 2019, Mississippi Power recorded pre-tax charges to income of an immaterial amount for the second quarter 2018 and $45$2 million ($331 million after tax) for year-to-date 2018,, 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 to costat up to $25$10 million pre-tax (excluding salvage, net of dismantlement costs), are expected tomay be incurred duringthrough the remainderfirst half of 2018 and 2019.2020. 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 $4$11 million for the remainder of 2018, $7 million in 2019 and $4$2 million to $6 million annually beginning in 2020.2020 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 this matterthese matters cannot be determined at this time.
The combined cycle and associated common facilities portions of the Kemper County energy facility were dedicated as Plant Ratcliffe on April 27, 2018.
Reserve Margin Plan
On August 6, 2018, Mississippi Power filed its proposed RMP, as required by the Mississippi PSC's order in the Kemper Settlement Docket. Under the RMP, Mississippi Power proposes alternatives that would reduce its reserve margin, with the most economic of the alternatives being the 2-year and 7-year acceleration of the retirement of Plant Watson Units 4 and 5, respectively, to the first quarter 2022 and the 4-year acceleration of the retirement of Plant Greene County Units 1 and 2 to the third quarter 2021 and the third quarter 2022, respectively, in order to lower or avoid operating costs. The Plant Greene County unit retirements would require the completion by Alabama Power of proposed transmission and system reliability improvements, as well as agreement by Alabama Power. The RMP filing also states that, in the event the Mississippi PSC ultimately approves an alternative that includes an accelerated retirement, Mississippi Power would require authorization to defer intime; however, they could have a regulatory asset for future recovery the remaining net book value of the units at the time of retirement. Mississippi Power expects the MPUS and other interested parties to review the proposal prior to resolution by the Mississippi PSC. The ultimate outcome of this matter cannot be determined at this time. However, if approved by the Mississippi PSC, the alternatives are not expected to have any adversematerial impact on customer rates.Mississippi Power's financial statements.
Income TaxOther Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Income Tax Matters" of Mississippi Power is involved in Item 7 of the Form 10-Kvarious other matters that could affect future earnings, including matters being litigated and FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk," Note (B) to the Condensed Financial Statements under "Regulatory Mattersregulatory matters. In addition, Mississippi Power," is subject to certain claims and Note (H) to the Condensed Financial Statements herein for information regarding the Tax Reform Legislation and related regulatory actions.legal actions arising

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Other Matters
Mississippi Power is involved in various other matters being litigated and regulatory matters that could affect future earnings. In addition, Mississippi Power is subject to certain claims and legal actions arising in the ordinary course of business. Mississippi Power's business activities are subject to extensive governmental regulation related to public health and the environment, such as laws and regulations governing air, water, land, and protection of 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 predicted at this time; however, for current proceedings not specifically reported in NoteNotes (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 NoteNotes (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.
On May 14, 2018, Mississippi Power's claim for lost revenue resulting from the Deepwater Horizon oil spill in theIn conjunction with Southern Company's sale of Gulf of Mexico in 2010 was settled. The settlement proceeds of $18 million, net of expenses and income tax, are included in Mississippi Power's earnings for the second quarter 2018.
To mitigate customer rate impacts associated with rising costs and declining sales,Power, Mississippi Power management approved an employee attrition plan on July 13, 2018.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 expects to recognizethat Gulf Power will retire its share of the costgenerating capacity of this plan, currently estimated to be between $8 million and $18 million, in the third quarter 2018.
Litigation
In 2016, a complaint againstPlant Daniel on January 15, 2024. Mississippi Power was filed in Harrison County Circuit Court (Circuit Court) by Biloxi Freezing & Processing Inc., Gulfside Casino Partnership, and John Carlton Dean, which was amended and refiledhas the option to include, among other things, Southern Company as a defendant. The individual plaintiff allegedpurchase 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 Southern Company violatedeconomic 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 Unfair Trade Practices Act. All plaintiffs alleged that MississippiPSC, 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 and Southern Company concealed, falsely represented, and failed to fully disclose important facts concerning the cost and schedule– Kemper County Energy Facility" in Item 8 of the Kemper County energy facility and that these alleged breaches unjustly enriched Mississippi Power and Southern Company. The plaintiffs sought unspecified actual damages and punitive damages; asked the Circuit Court to appoint a receiver to oversee, operate, manage, and otherwise control all affairs relating to the Kemper County energy facility; asked the Circuit Court to revoke any licenses or certificates authorizing Mississippi Power or Southern Company to engage in any business related to the Kemper County energy facility in Mississippi; and sought attorney's fees, costs, and interest. The plaintiffs also sought an injunction to prevent any Kemper County energy facility costs from being charged to customers through electric rates. Form 10-K for additional information.
In June 2017, the Circuit Court ruled in favor of motions by Southern Company and Mississippi Power and dismissed the case. In July 2017, the plaintiffs filed notice of an appeal. On July 13, 2018, Mississippi Power and Southern Company reached a settlement agreement with the plaintiffs and the plaintiffs' appeal was dismissed with prejudice. The settlement had no material impact on Mississippi Power's financial statements.
On May 18, 2018, Southern Company and Mississippi Power received a notice of dispute and arbitration demand filed by Martin Product Sales, LLC (Martin) based on two agreements, both related to Kemper IGCC byproducts for which Mississippi Power provided termination notices in September 2017. Martin alleges breach of contract, breach of good faith and fair dealing, fraud and misrepresentation, and civil conspiracy and makes a claim for damages in the amount of approximately $143 million, as well as additional unspecified damages, attorney's fees, costs, and interest. In the first quarter 2019, Mississippi Power believes this legal challenge has no merit; however,and Southern Company filed motions to dismiss.
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 in the refund process by applying an adverse outcome in this proceeding couldincorrect 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 material impact on Mississippi Power's results of operations, financial condition, andmotion to dismiss the amended complaint.

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MISSISSIPPI POWER COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

liquidity. Mississippi Power will vigorously defend itselfbelieves these legal challenges have no merit; however, an adverse outcome in this matter, theeither of these proceedings could have a material impact on Mississippi Power's results of operations, financial condition, and liquidity. The ultimate outcome of whichthese 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 NoteNotes 1, 5, and 6 to the financial statements of Mississippi Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Mississippi Power's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Mississippi Power in Item 7 of the Form 10-K for a complete discussion of Mississippi Power's critical accounting policies and estimates.
Kemper County Energy Facility Closure Costs
As of June 30, 2018, Mississippi Power recorded charges to income of an immaterial amount for the second quarter 2018 and $45 million ($33 million after tax) for year-to-date 2018, primarily resulting from the abandonment and related closure activities for the mine and gasifier-related assets at the Kemper County energy facility. Additional closure costs for the mine and gasifier-related assets, currently estimated to cost up to $25 million pre-tax (excluding salvage, net of dismantlement costs), are expected to be incurred during the remainder of 2018 and 2019. In addition, period costs, including, but not limited to, costs for compliance and safety, ARO accretion, and property taxes for the mine and gasifier-related assets, are estimated at $4 million for the remainder of 2018, $7 million in 2019, and $4 million annually beginning in 2020. The ultimate outcome of this matter cannot be determined at this time.
See Notes 1 and 3 to the financial statements of Mississippi Power under "Variable Interest Entities" and "Kemper County Energy Facility," respectively, in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Kemper County Energy Facility" herein for additional information.
Recently Issued Accounting Standards
See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Recently Issued Accounting Standards" of Mississippi Power in Item 7 of the Form 10-K for additional information regarding ASU No. 2016-02, Leases (Topic 842). See Note (A) to the Condensed Financial Statements herein for information regarding Mississippi Power's recently adopted accounting standards.
FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Mississippi Power in Item 7 of the Form 10-K for additional information.
Mississippi Power's cash requirements primarily consist of funding ongoing operations, 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.
In March 2018, Mississippi Power issued $300 million aggregate principal amount of Series 2018A Floating Rate Senior Notes due March 27, 2020 bearing interest based on three-month LIBOR and $300 million aggregate principal amount of Series 2018B 3.95% Senior Notes due March 30, 2028. In March 2018, Mississippi Power also entered into a $300 million short-term floating rate bank loan bearing interest based on one-month LIBOR, of which

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

$200 million was repaid in the second quarter 2018 and $50 million was repaid on July 31, 2018. Mississippi Power used the proceeds from these financings to repay a $900 million unsecured term loan.
Net cash provided fromused for operating activities totaled $297$23 million for the first sixthree months of 2018, an increase2019, a decrease of $162$39 million as compared to the corresponding period in 2017.2018. The increasedecrease in net cash provided fromused for operating activities is primarily related to increasedlower income tax refunds in 2018, partially offset by an increase inand ad valorem taxes and the timing of collections of receivables.tax payments in 2019. Net cash used for investing activities totaled $108$63 million for the first sixthree months of 20182019 primarily due to gross property additions related to steam production, distribution and transmission.transmission facilities. Net cash used forprovided from financing activities totaled $209$5 million for the first sixthree months of 20182019 primarily due to redemptions$43 million of long-term debt,pollution control revenue bonds reoffered to the public, partially offset by the issuancea return of senior notes and short-term borrowings.capital 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 sixthree months of 20182019 include increasesa decrease of $425$259 million in long-term debt, primarily due to the issuancereclassification of $300 million in unsecured senior notes and $96to securities due within one year, partially offset by $43 million in notes payablesecurities reoffered to the public; a decrease of $62 million in accrued taxes primarily due to the issuancepayment of ad valorem taxes; and a short-term bank loan.decrease of $81 million in cash and cash equivalents. Other significant changes include a net changedecrease of $307$79 million in accumulated deferred income taxesplant in service and an increase of $99 million in other property and investments primarily due to the tax abandonment of the Kemper IGCC, as wella new tolling arrangement, effective January 1, 2019, accounted for as a decrease of $732 million in securities due within one year duesales-type lease. See Note (L) to the repayment of a $900 million unsecured term loan.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 $124$300 million

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

will be required through June 30, 2019March 31, 2020 to fund maturities of long-term debt and $100 million will be required to fund maturities of short-term debt. In addition, Mississippi Power has $40 million of tax-exempt variable rate demand obligations that are supported by short-term credit facilities and approximately $93 million of revenue bonds that were required to be remarketed over the next 12 months. Subsequent to June 30, 2018, Mississippi Power purchased and held approximately $43 million of these pollution control revenue bonds. See "Sources of Capital" herein for additional information.
Mississippi Power's purchase commitments related to LTSAs have changed to approximately $43 million for 2018, $28 million for 2019, $28 million for 2020, $29 million for 2021, $49 million for 2022, and $257 million for 2023 and thereafter due to an increase in estimated expenditures covered under the LTSA for the Kemper County energy facility.
The construction program is subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; storm impacts; changes in environmental laws and regulations; the outcome of any legal challenges to environmental rules; changes in generating plants, including unit retirements and replacements and adding or changing fuel sources at existing electric generating units, to meet regulatory requirements; changes in FERC rules and regulations; Mississippi PSC approvals; changes in the expected environmental compliance program; changes in legislation; the cost and efficiency of construction labor, equipment, and materials; project scope and design changes; and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered.
Sources of Capital
Mississippi Power plans to obtain the funds required for construction and other purposesto meet its future capital needs from operating cash flows, lines of credit, bank term loans, external securitysecurities issuances, borrowings from financial institutions, including commercial paper (toto the extent itMississippi Power is eligible to participate), monetization of income tax deductions associated with the abandonment of the gasifier portion of the Kemper County energy facility,participate, and equity contributions from Southern Company. TheHowever, the amount, type, and timing of any future financingsfinancing, if needed, will depend upon regulatory approval, prevailing market conditions, regulatory approval, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" in Item 7 of the Form 10-K for additional information.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

As of June 30, 2018,March 31, 2019, Mississippi Power's current liabilities exceeded current assets by approximately $117$120 million primarily as a result of $224$339 million of long-term debt that maturesis due within the next 12 months. Mississippi Power intends to continue to monitor its access to short-term and long-term capital markets as well as its bank credit arrangements to meet future capital and liquidity needs.one year.
At June 30, 2018,March 31, 2019, Mississippi Power had approximately $228$212 million of cash and cash equivalents. CommittedMississippi Power's committed credit arrangements with banks totaled $100 million at June 30, 2018 were as follows:
Expires   
Executable Term
Loans
 
Expires Within One
Year
2018 Total Unused 
One
Year
 
Term
Out
 
No Term
Out
(in millions)
$100
 $100
 $100
 $
 $
 $100
March 31, 2019, all of which was unused. These credit arrangements expire in 2019.
See Note 68 to the financial statements of Mississippi Power under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
All of these bank credit arrangements as well as Mississippi Power's term loan agreement, contain covenants that limit debt levels and typically contain cross accelerationcross-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, 2018,March 31, 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 seek to renew or replace its credit arrangements as needed, prior to expiration. In connection therewith, Mississippi Power may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
A portion of the $100 million unused credit arrangements with banks is allocated to provide liquidity support to Mississippi Power's variable rate revenue bonds. The amount of variable rate revenue bonds outstanding requiring liquidity support as of June 30, 2018March 31, 2019 was approximately $40 million. In addition,
Short-term debt, including the average amount and maximum amount outstanding, was immaterial at June 30, 2018, March 31, 2019 and during the three-month period ended March 31, 2019.
Mississippi Power had approximately $93 millionbelieves the need for working capital can be adequately met by utilizing lines of revenue bonds outstanding that were requiredcredit, short-term bank notes, commercial paper to be remarketed within the next 12 months.
In June 2018,extent Mississippi Power gave notice that approximately $43 million of its pollution control revenue bonds would be subjectis eligible to mandatory tender in July 2018. Subsequent to June 30, 2018, Mississippi Power purchasedparticipate, operating cash flows, and held these bonds, which may be remarketed to the public in the future.other cash.
Short-term borrowings are included in notes payable in the balance sheets. Details of short-term borrowings were as follows:
  Short-term Debt at June 30, 2018 
Short-term Debt During the Period(*)
  
Amount
Outstanding
 
Weighted
Average
Interest
Rate
 
Average
Amount
Outstanding
 
Weighted
Average
Interest
Rate
 
Maximum
Amount
Outstanding
  (in millions)   (in millions)   (in millions)
Short-term bank debt $100
 3.3% $213
 1.7% $300
(*)Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 2018.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Credit Rating Risk
At June 30, 2018,See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" of Mississippi Power doesin Item 7 of the Form 10-K for additional information.
At March 31, 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.
In October 2017, Mississippi Power executed agreements with its largest retail customer, Chevron, to continue providing retail service to the Chevron refinery in Pascagoula, Mississippi through 2038. The agreements grant Chevron a security interest in the co-generation assets, with a net book value of approximately $91 million, located at the refinery that is exercisable upon the occurrence of (i) certain bankruptcy events or (ii) other events of default coupled with specific reductions in steam output at the facility and a downgrade of Mississippi Power's credit rating to below investment grade by two of the three rating agencies.
There are certain contracts that have required or could require collateral, but not accelerated payment, in the event of a credit rating change to BBB and/or Baa2 or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, energy price risk management, and transmission. At June 30, 2018,March 31, 2019, the maximum potential collateral requirements at a rating below BBB- and/or Baa3 equaled approximately $198$281 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 or, at a minimum,and would be likely to impact the cost at which it does so.
On February 26, 2018, Moody's revised its rating outlook for Mississippi Power from stable to positive.
On March 14, 2018, S&P upgraded the senior unsecured long-term debt rating of Mississippi Power to A- from BBB+. The outlook remained negative.
As a result of the Tax Reform Legislation, certain financial metrics, such as the funds from operations to debt percentage, used by the credit rating agencies to assess Southern Company and its subsidiaries, including Mississippi Power, may be negatively impacted. The settlement agreement approved by the Mississippi PSC in August 2018 with respect to the 2018 PEP Settlement Agreementfilings 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. In addition, Mississippi Power has committed to seek equity contributions sufficient to restore its equity ratio to the 50% target. See Note 32 to the financial statements of Mississippi Power under "Retail Regulatory Matters""Mississippi Power" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory MattersMississippi Power" herein for additional information.
Financing Activities
In March 2018,2019, Mississippi Power issued $300 million aggregate principal amount of Series 2018A Floating Rate Senior Notes due March 27, 2020 bearing interest based on three-month LIBOR and $300 million aggregate principal amount of Series 2018B 3.95% Senior Notes due March 30, 2028. In March 2018, Mississippi Power also entered into a $300 million short-term floating rate bank loan bearing interest based on one-month LIBOR, of which $200 million was repaid inreoffered to the second quarter 2018 and $50 million was repaid on July 31, 2018. Mississippi Power used the proceeds from these financings to repay a $900 million unsecured term loan.
Subsequent to June 30, 2018, approximatelypublic $43 million in pollution control revenue bonds of Mississippi Power wereBusiness Finance Corporation Pollution Control Revenue Refunding Bonds, Series 2002, that previously had been purchased and held by Mississippi Power. These bonds may be remarketed to the public in the future.
In addition to any financings that may be necessary to meet capital requirements and contractual obligations, Mississippi Power plans, when economically feasible, to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.

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CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
 
For the Three Months
Ended June 30,
 For the Six Months
Ended June 30,
For the Three Months
Ended March 31,
2018 2017 2018 20172019 2018
(in millions) (in millions)(in millions)
Operating Revenues:          
Wholesale revenues, non-affiliates$443
 $436
 $867
 $783
$352
 $424
Wholesale revenues, affiliates109
 90
 192
 190
87
 83
Other revenues3
 3
 5
 6
4
 2
Total operating revenues555
 529
 1,064
 979
443
 509
Operating Expenses:          
Fuel153
 139
 321
 271
145
 169
Purchased power39
 40
 100
 70
24
 61
Other operations and maintenance91
 97
 184
 190
84
 93
Depreciation and amortization125
 129
 240
 247
119
 114
Taxes other than income taxes12
 12
 24
 24
11
 12
Asset impairment119
 
 119
 
Total operating expenses539

417
 988
 802
383
 449
Operating Income16
 112
 76
 177
60
 60
Other Income and (Expense):          
Interest expense, net of amounts capitalized(46) (48) (93) (97)(44) (47)
Other income (expense), net2
 2
 5
 (2)2
 3
Total other income and (expense)(44) (46) (88) (99)(42) (44)
Earnings (Loss) Before Income Taxes(28) 66
 (12) 78
Earnings Before Income Taxes18
 16
Income taxes (benefit)(73) (38) (172) (90)(9) (99)
Net Income45
 104
 160
 168
27
 115
Net income attributable to noncontrolling interests23
 22
 17
 17
Net loss attributable to noncontrolling interests(29) (6)
Net Income Attributable to Southern Power$22
 $82
 $143
 $151
$56
 $121
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
 
 For the Three Months
Ended June 30,
 For the Six Months
Ended June 30,
 2018 2017 2018 2017
 (in millions) (in millions)
Net Income$45
 $104
 $160
 $168
Other comprehensive income (loss):       
Qualifying hedges:       
Changes in fair value, net of tax of
$(19), $24, $(3), and $20, respectively
(55) 40
 (8) 32
Reclassification adjustment for amounts included in net income,
net of tax of $20, $(27), $12, and $(30), respectively
59
 (45) 35
 (48)
Pension and other postretirement benefit plans:       
Reclassification adjustment for amounts included in net income,
net of tax of $-, $-, $-, and $-, respectively

 
 1
 
Total other comprehensive income (loss)4
 (5) 28
 (16)
Comprehensive Income49
 99
 188
 152
Comprehensive income attributable to noncontrolling interests23
 22
 17
 17
Comprehensive Income Attributable to Southern Power$26
 $77
 $171
 $135
The accompanying notes as they relate to Southern Power are an integral part of these condensed consolidated financial statements.

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
 For the Six Months
Ended June 30,
 2018 2017
 (in millions)
Operating Activities:   
Net income$160
 $168
Adjustments to reconcile net income to net cash provided from operating activities —   
Depreciation and amortization, total256
 264
Deferred income taxes(252) 91
Amortization of investment tax credits(29) (28)
Deferred revenues(19) (34)
Income taxes receivable, non-current(4) (58)
Asset impairment119
 
Other, net13
 (1)
Changes in certain current assets and liabilities —   
-Receivables(30) (58)
-Prepaid income taxes(36) 33
-Other current assets3
 20
-Accounts payable(41) (45)
-Accrued taxes15
 4
-Other current liabilities(28) (8)
Net cash provided from operating activities127
 348
Investing Activities:   
Business acquisitions(64) (1,004)
Property additions(198) (145)
Change in construction payables2
 (167)
Payments pursuant to LTSAs(32) (68)
Other investing activities15
 (3)
Net cash used for investing activities(277) (1,387)
Financing Activities:   
Increase (decrease) in notes payable, net(41) 189
Proceeds —   
Short-term borrowings200
 
Capital contributions from parent company16
 
Redemptions —   
Return of paid in capital(250) 
Senior notes(350) 
Other long-term debt(420) (3)
Distributions to noncontrolling interests(42) (40)
Capital contributions from noncontrolling interests1,210
 73
Payment of common stock dividends(156) (158)
Other financing activities(15) (18)
Net cash provided from financing activities152
 43
Net Change in Cash, Cash Equivalents, and Restricted Cash2
 (996)
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period140
 1,112
Cash, Cash Equivalents, and Restricted Cash at End of Period$142
 $116
Supplemental Cash Flow Information:   
Cash paid (received) during the period for —   
Interest (net of $10 and $4 capitalized for 2018 and 2017, respectively)$109
 $113
Income taxes, net109
 (117)
Noncash transactions — Accrued property additions at end of period33
 19
The accompanying notes as they relate to Southern Power are an integral part of these condensed consolidated financial statements.

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
Assets At June 30, 2018 At December 31, 2017
  (in millions)
Current Assets:    
Cash and cash equivalents $142
 $129
Receivables —    
Customer accounts receivable 165
 117
Affiliated 60
 50
Other 63
 98
Materials and supplies 213
 278
Prepaid income taxes 82
 50
Assets held for sale, current 17
 1
Other current assets 31
 35
Total current assets 773
 758
Property, Plant, and Equipment:    
In service 13,402
 13,755
Less: Accumulated provision for depreciation 1,959
 1,910
Plant in service, net of depreciation 11,443
 11,845
Construction work in progress 771
 511
Total property, plant, and equipment 12,214
 12,356
Other Property and Investments:    
Intangible assets, net of amortization of $60 and $47
at June 30, 2018 and December 31, 2017, respectively
 398
 411
Total other property and investments 398
 411
Deferred Charges and Other Assets:    
Prepaid LTSAs 93
 118
Accumulated deferred income taxes 1,223
 925
Income taxes receivable, non-current 81
 72
Assets held for sale 183
 
Other deferred charges and assets 463
 566
Total deferred charges and other assets 2,043
 1,681
Total Assets $15,428
 $15,206
The accompanying notes as they relate to Southern Power are an integral part of these condensed consolidated financial statements.

SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
Liabilities and Stockholders' Equity At June 30, 2018 At December 31, 2017
  (in millions)
Current Liabilities:    
Securities due within one year $
 $770
Notes payable 264
 105
Accounts payable —    
Affiliated 75
 102
Other 84
 103
Liabilities held for sale, current 2
 
Other current liabilities 146
 152
Total current liabilities 571
 1,232
Long-term Debt 5,037
 5,071
Deferred Credits and Other Liabilities:    
Accumulated deferred income taxes 135
 199
Accumulated deferred ITCs 1,856
 1,884
Other deferred credits and liabilities 255
 322
Total deferred credits and other liabilities 2,246
 2,405
Total Liabilities 7,854
 8,708
Common Stockholder's Equity:    
Common stock, par value $0.01 per share —    
Authorized — 1,000,000 shares    
Outstanding — 1,000 shares 
 
Paid-in capital 3,023
 3,662
Retained earnings 1,464
 1,478
Accumulated other comprehensive income (loss) 31
 (2)
Total common stockholder's equity 4,518
 5,138
Noncontrolling interests 3,056
 1,360
Total stockholders' equity 7,574
 6,498
Total Liabilities and Stockholders' Equity $15,428
 $15,206
 For the Three Months
Ended March 31,
 2019 2018
 (in millions)
Net Income$27
 $115
Other comprehensive income (loss):   
Qualifying hedges:   
Changes in fair value, net of tax of $(10) and $16, respectively(29) 48
Reclassification adjustment for amounts included in net income,
net of tax of $8 and $(8), respectively
25
 (24)
Total other comprehensive income (loss)(4) 24
Comprehensive Income23
 139
Comprehensive loss attributable to noncontrolling interests(29) (6)
Comprehensive Income Attributable to Southern Power$52
 $145
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 Three Months
Ended March 31,
 2019 2018
 (in millions)
Operating Activities:   
Net income$27
 $115
Adjustments to reconcile net income to net cash provided from operating activities —   
Depreciation and amortization, total125
 122
Deferred income taxes17
 (50)
Amortization of investment tax credits(14) (14)
Other, net(7) 2
Changes in certain current assets and liabilities —   
-Receivables10
 48
-Prepaid income taxes(9) (32)
-Other current assets3
 5
-Accounts payable(32) (43)
-Accrued compensation(15) (13)
-Other current liabilities5
 9
Net cash provided from operating activities110
 149
Investing Activities:   
Business acquisitions(2) (46)
Property additions(66) (121)
Change in construction payables(7) 25
Payments pursuant to LTSAs(15) (18)
Other investing activities11
 7
Net cash used for investing activities(79) (153)
Financing Activities:   
Increase in notes payable, net5
 29
Distributions to noncontrolling interests(36) (13)
Capital contributions from noncontrolling interests3
 8
Payment of common stock dividends(51) (78)
Net cash used for financing activities(79) (54)
Net Change in Cash, Cash Equivalents, and Restricted Cash(48) (58)
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period181
 140
Cash, Cash Equivalents, and Restricted Cash at End of Period$133
 $82
Supplemental Cash Flow Information:   
Cash paid (received) during the period for —   
Interest (net of $4 and $5 capitalized for 2019 and 2018, respectively)$28
 $29
Income taxes, net1
 (39)
Noncash transactions — Accrued property additions at end of period19
 57
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 March 31, 2019 At December 31, 2018
  (in millions)
Current Assets:    
Cash and cash equivalents $133
 $181
Receivables —    
Customer accounts receivable 120
 111
Affiliated 33
 55
Other 116
 116
Materials and supplies 218
 220
Prepaid income taxes 1,190
 25
Other current assets 37
 37
Total current assets 1,847
 745
Property, Plant, and Equipment:    
In service 13,284
 13,271
Less: Accumulated provision for depreciation 2,288
 2,171
Plant in service, net of depreciation 10,996
 11,100
Construction work in progress 409
 430
Total property, plant, and equipment 11,405
 11,530
Other Property and Investments:    
Intangible assets, net of amortization of $67 and $61
at March 31, 2019 and December 31, 2018, respectively
 340
 345
Other investments 2
 
Total other property and investments 342
 345
Deferred Charges and Other Assets:    
Operating lease right-of-use assets, net of amortization 372
 
Prepaid LTSAs 102
 98
Accumulated deferred income taxes 17
 1,186
Income taxes receivable, non-current 33
 30
Assets held for sale 644
 576
Other deferred charges and assets 342
 373
Total deferred charges and other assets 1,510
 2,263
Total Assets $15,104
 $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 March 31, 2019 At December 31, 2018
  (in millions)
Current Liabilities:    
Securities due within one year $599
 $599
Notes payable 105
 100
Accounts payable —    
Affiliated 69
 92
Other 66
 77
Accrued income taxes 11
 6
Accrued interest 44
 36
Liabilities held for sale 9
 15
Other current liabilities 111
 106
Total current liabilities 1,014
 1,031
Long-term Debt 4,396
 4,418
Deferred Credits and Other Liabilities:    
Accumulated deferred income taxes 107
 105
Accumulated deferred ITCs 1,817
 1,832
Operating lease obligations 371
 
Other deferred credits and liabilities 181
 213
Total deferred credits and other liabilities 2,476
 2,150
Total Liabilities 7,886
 7,599
Total Stockholders' Equity (See accompanying statements)
 7,218
 7,284
Total Liabilities and Stockholders' Equity $15,104
 $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 company1
 
 
 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
            
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 company1
 
 
 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
The accompanying notes as they relate to Southern Power are an integral part of these condensed financial statements.

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SECONDFIRST QUARTER 20182019 vs. SECONDFIRST QUARTER 2017
AND
YEAR-TO-DATE 2018 vs. YEAR-TO-DATE 2017


OVERVIEW
Southern Power develops, constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Power continually seeks opportunities to execute its strategy to create value through various transactions including acquisitions, dispositions, and sales of assets,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 has committedcommits to the construction or acquisition of new generating capacity only after entering into or assuming long-term PPAs for the new facilities.
In May 2018,During the three months ended March 31, 2019, Southern Power completedcontinued construction of the sale100-MW Wildhorse Mountain wind facility, the 200-MW Reading wind facility, and the expansion of a 33% equity interest in SPSH, a newly-formed limited partnership indirectly owning substantially all of Southern Power's solar facilities,the 385-MW Mankato natural gas facility. See FUTURE EARNINGS POTENTIAL "Construction Projects" herein for an aggregate purchase price of approximately $1.2 billion, subject to customary working capital adjustments. Southern Power maintains control and overall operational responsibilities for the solar facilities.additional information.
Also in MayIn November 2018, Southern Power entered into an agreement to sell all of its equity interests in two natural gas-fired operating facilities, Plant Oleander and Plant Stanton Unit A (together,Mankato (including the Florida Plants),385-MW expansion currently under construction) for an aggregate purchase price of $195approximately $650 million. The completion of the disposition is subject to the expansion unit reaching commercial operation as well as various other customary conditions to closing, including FERC and state commission approvals. On April 17, 2019, Southern Power entered into an agreement to sell all of its equity interests in the Nacogdoches biomass-fueled facility to Austin Energy for an aggregate purchase price of $460 million, subject to customary closing conditions and working capital and timing adjustments. The sale is subject to certain closing and timing conditions and approvals andEach of these sales is expected to occurclose in mid-2019; however, the first half of 2019. As a result of this pending transaction, Southern Power recorded an asset impairment charge of approximately $119 million ($89 million after tax) in the second quarter 2018. See Note (J) to the Condensed Financial Statements under "Southern Power" herein for additional information. The ultimate outcome of this matterthese matters cannot be determined at this time.
Southern Power is pursuing the sale of a noncontrolling interest in a portfolio of eight operating wind facilities through the use of third-party tax equity, which, if successful, is expected to close in the fourth quarter 2018. See FUTURE EARNINGS POTENTIAL "Income Tax MattersLegal Entity Reorganizations" herein for additional information. The ultimate outcome of this matter cannot be determined at this time.
During the six months ended June 30, 2018, Southern Power acquired and placed in-service the 20-MW Gaskell West 1 solar facility, acquired and began construction of the 100-MW Wild Horse Mountain wind facility, and continued construction of the 148-MW Cactus Flats wind facility and the expansion of the 345-MW Mankato natural gas facility. See FUTURE EARNINGS POTENTIAL "Acquisitions" and "Construction Projects" herein for additional information.
At June 30, 2018,March 31, 2019, Southern Power's average investment coverage ratio for its generating assets (including the Florida Plants)Plants Mankato and Nacogdoches), based on the ratio of investment under contract to total investment using the respective generation facilities' net book value (or expected in-service value for facilities under construction and acquisitions discussed herein)construction) as the investment amount, was 92%93% through 20222023 and 90%91% through 2027,2028, with an average remaining contract duration of approximately 15 years. See FUTURE EARNINGS POTENTIAL "Power Sales Agreements" herein for additional information.
See FINANCIAL CONDITION AND LIQUIDITY "Capital Requirements and Contractual Obligations" herein for information regarding Southern Power's revised capital expenditure forecasts for 2018 through 2022.
Southern Power continues to focus on several key performance indicators, including, but not limited to, peak season equivalent forced outage rate, contract availability, and net income.

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RESULTS OF OPERATIONS
Net Income Attributable to Southern Power
Second Quarter 2018 vs. Second Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(60) (73.2) $(8) (5.3)
First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change)
$(65) (53.7)
Net income attributable to Southern Power for the secondfirst quarter 20182019 was $22$56 million compared to $82$121 million for the corresponding period in 2017. Net income attributable to Southern Power for year-to-date 20182018. The decrease was $143 million compared to $151 million for the corresponding period in 2017. The decreases were primarily due to a $119 million asset impairment charge ($89 million after tax) as a result of the pending sale of the Florida Plants. The year-to-date decrease was partially offset by approximately $54$50 million in state income tax benefits recorded in 2018 arising from the reorganization of Southern Power's legal entities that own and operate itscertain solar facilities.facilities and a reduction in 2019 of $39 million in PTCs, partially offset by $28 million in HLBV income allocations to Southern Power related to tax equity partnerships entered into in 2018. See Notes 7 and 10 to the financial statements in Item 8 of the Form 10-K for additional information on the legal entity reorganization and the tax equity partnerships, respectively.

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Operating Revenues
Second Quarter 2018 vs. Second Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$26 4.9 $85 8.7
First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change)
$(66) (13.0)
Total operating revenues include PPA capacity revenues, which are derived primarily from long-term contracts involving natural gas and biomass generating facilities, and PPA energy revenues from Southern Power's generation facilities. To the extent Southern Power has capacity not contracted under a PPA, it may sell power into thean accessible wholesale market, and,or, to the extent thethose generation assets are part of the FERC-approved IIC, as approved by the FERC, it may sell power into the power pool.
Natural Gas and Biomass Capacity and Energy Revenue
Capacity revenues generally represent the greatest contribution to netoperating income and are designed to provide recovery of fixed costs plus a return on investment.
Energy is generally sold at variable cost or is indexed to published natural gas indices. Energy revenues will vary depending on the energy demand of Southern Power's customers and their generation capacity, as well as the market prices of wholesale energy compared to the cost of Southern Power's energy. Energy revenues also include fees for support services, fuel storage, and unit start charges. Increases and decreases in energy revenues under PPAs that are driven by fuel or purchased power prices are accompanied by an increase or decrease in fuel and purchased power costs and do not have a significant impact on net income.
Solar and Wind Energy Revenue
Southern Power's energy sales from solar and wind generating facilities are predominantly through long-term PPAs that do not have a capacity charge. Customers either purchase the energy output of a dedicated renewable facility through an energy charge or pay a fixed price related to the energy 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:
 First Quarter 2019 First Quarter 2018
 (in millions)
PPA capacity revenues$127
 $138
PPA energy revenues227
 254
Total PPA revenues354
 392
Non-PPA revenues85
 115
Other revenues4
 2
Total operating revenues$443
 $509

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Details of Southern Power's operating revenues were as follows:
 Second Quarter 2018 Second Quarter 2017 Year-to-Date 2018 Year-to-Date 2017
 (in millions)
PPA capacity revenues$144
 $149
 $282
 $298
PPA energy revenues302
 270
 556
 466
Total PPA revenues446
 419
 838
 764
Non-PPA revenues106
 107
 221
 209
Other revenues3
 3
 5
 6
Total operating revenues$555
 $529
 $1,064
 $979
In the secondfirst quarter 2018,2019, total operating revenues were $555$443 million, reflecting a $26$66 million, or 5%13%, increasedecrease from the corresponding period in 2017.2018. The increasedecrease in operating revenues was primarily due to the following:
PPA capacity revenues decreased $5$11 million, or 3%8%, primarily due to a decrease of $17 million attributable to the contractual expirationsale of an affiliatePlant Oleander and Plant Stanton Unit A (together, the Florida Plants) in December 2018, partially offset by a $5 million increase in new PPA capacity revenues from existing natural gas PPA.facilities.
PPA energy revenues increased $32decreased $27 million, or 12%11%, primarily due to an $18a $22 million increase from newdecrease in sales related to natural gas PPAs from existing facilities, driven by a $51 million decrease in the average cost of fuel and purchased power, partially offset by a $10$29 million increase from renewable facilities primarily due to an increase in the volume of KWHs sold including new solar facilities in service.due to increased customer load.
For year-to-date 2018, total operatingNon-PPA revenues were $1.1 billion, reflecting an $85decreased $30 million, or 9%26%, increase from the corresponding period in 2017. The increase in operating revenues was primarily due to the following:
PPA capacity revenues decreased $16a $21 million or 5%, primarily due to the contractual expiration of an affiliate natural gas PPA.
PPA energy revenues increased $90 million, or 19%, primarily due to $37 million in increased fuel costs that are contractually recovered through existing PPAs, a $36 million increase from new natural gas PPAs from existing facilities, and an $18 million increase from renewable facilities primarily due to an increasedecrease in the volume of KWHs sold including new solar facilities in service.
Non-PPA revenues increased $12 million, or 6%,through short-term sales, primarily due to an increasea reduction in the volume of KWHs sold from uncovered natural gas capacity, through short-term sales.and an $8 million decrease in the market price of energy.
Fuel and Purchased Power Expenses
Fuel costs constitute one of the largest expenses for Southern Power. In addition, Southern Power purchases a portion of its electricity needs from the wholesale market including the power pool. Details of Southern Power's generation and purchased power were as follows:
 Second Quarter 2018Second Quarter 2017 Year-to-Date 2018Year-to-Date 2017
 (in billions of KWHs)
Generation12.210.9 22.020.6
Purchased power1.21.2 2.22.2
Total generation and purchased power13.412.1 24.222.8
      
Total generation and purchased power, excluding solar, wind, and tolling agreements7.25.6 13.910.5

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 First Quarter 2019First Quarter 2018
 (in billions of KWHs)
Generation10.1
9.8
Purchased power0.7
0.9
Total generation and purchased power10.8
10.7
   
Total generation and purchased power, excluding solar, wind, and tolling agreements6.6
6.7
Southern Power's PPAs for natural gas and biomass generation generally provide that the purchasers are responsible for either procuring the fuel (tolling agreements) or reimbursing Southern Power for substantially all of the cost of fuel relating to the energy delivered under such PPAs. Consequently, changes in such fuel costs are generally accompanied by a corresponding change in related fuel revenues and do not have a significant impact on net income. Southern Power is responsible for the cost of fuel for generating units that are not covered under PPAs. Power from these generating units is sold into the wholesale market or into the power pool for capacity owned directly by Southern Power.
Purchased power expenses will vary depending on demand, availability, and the cost of generating resources throughout the Southern Company system and other contract resources. Load requirements are submitted to the power pool on an hourly basis and are fulfilled with the lowest cost alternative, whether that is generation owned by Southern Power, an affiliate company, or external parties. Such purchased power costs are generally recovered through PPA revenues.
Details of Southern Power's fuel and purchased power expenses were as follows:
Second Quarter 2018 vs. Second Quarter 2017 
Year-to-Date 2018 vs.
Year-to-Date 2017
First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change) (change in millions) (% change)(change in millions) (% change)
Fuel$14
 10.1 $50
 18.5$(24) (14.2)
Purchased power(1) (2.5) 30
 42.9(37) (60.7)
Total fuel and purchased power expenses$13
 $80
 $(61) 
In the secondfirst quarter 2018,2019, total fuel and purchased power expenses increased $13decreased $61 million, or 7%27%, compared to the corresponding period in 2017.2018. Fuel expense increased $14decreased $24 million primarily due to a $48 million increase in the volume of KWHs generated, excluding solar, wind, and tolling agreements, partially offset by a $37 million decrease inassociated with the average cost of natural gas per KWH generated.
For year-to-date 2018, total fuel and purchased power expenses increased $80 million, or 23%, compared to the corresponding period in 2017. Fuel expense increased $50 million primarily due to a $108 million increase in the volume of KWHs generated, excluding solar, wind, and tolling agreements, partially offset by a $59 million decrease in the average cost of natural gas per KWH generated. Purchased power expense increased $30decreased $37 million primarily due to an increase in the average cost of purchased power in first quarter 2018.
Asset Impairment
In the second quarter 2018, a $119 million asset impairment charge was recorded as a result of the pending sale of the Florida Plants, expected to occur in the first half 2019.
See Note (J) under "Southern Power – Sale of Florida Plants" to the Condensed Financial Statements herein for additional information.
Income Taxes (Benefit)
Second Quarter 2018 vs. Second Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(35) (92.1) $(82) (91.1)
In the second quarter 2018, income tax benefit was $73 million compared to $38 million for the corresponding period in 2017. For year-to-date 2018, income tax benefit was $172 million compared to $90 million for the corresponding period in 2017. The increases were primarily due to lower pre-tax earnings, primarily resulting from the asset impairment charge, and income tax benefits arising from a reorganization of Southern Power's legal entities that own and operate substantially all of its solar facilities related to certain changes in state apportionment$24

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rates.million decrease associated with the average cost of purchased power and a $13 million decrease associated with the volume of KWHs purchased.
Other Operations and Maintenance Expenses
First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change)
$(9) (9.7)
In the first quarter 2019, other operations and maintenance expenses were $84 million compared to $93 million for the corresponding period in 2018. The decrease was primarily due to lower scheduled outage and maintenance expenses and the recovery of legal costs related to the Roserock settlement agreement. See FUTURE EARNINGS POTENTIALNote (C) to the Condensed Financial Statements under "General Litigation Matters"Southern Power" herein for additional information.
Income Tax MattersLegal Entity Reorganizations"Taxes (Benefit)
First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change)
$90 90.9
In the first quarter 2019, income tax benefit was $9 million compared to $99 million for the corresponding period in 2018. This change was primarily due to $50 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 $39 million reduction of tax benefits from wind PTCs primarily as a result of the sale of a noncontrolling tax equity interest in SP Wind. See Note (H)(G) to the Condensed Financial Statements herein for additional information.
Net Loss Attributable to Noncontrolling Interests
First Quarter 2019 vs. First Quarter 2018
(change in millions)(% change)
$23N/M
In the first quarter 2019, net loss attributable to noncontrolling interests was $29 million compared to $6 million for the corresponding period in 2018. The increase was primarily related to tax equity partnerships entered into in 2018. See Note 7 to the financial statements in Item 8 of the Form 10-K under "Southern Power" 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 and the pending dispositions of Plants Mankato and Nacogdoches in 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 successful remarketing of capacity as current contracts expire; and Southern Power's ability to execute its growth strategy including successful additional investments inthrough the development or acquisition of renewable facilities and other energy projects, and to develop and construct generating facilities.projects.
In May 2018, Southern Power completed the sale of a 33% equity interest in SPSH, a newly-formed limited partnership indirectly owning substantially all of Southern Power's solar facilities, to Global Atlantic Financial Group Limited (Global Atlantic) for approximately $1.2 billion, subject to customary working capital adjustments. Accordingly, Global Atlantic will receive 33% of all cash distributions paid by SPSH. Southern Power continues to consolidate the assets and liabilities of SPSH with Global Atlantic's share of partnership earnings reflected in net income attributable to noncontrolling interests in the Condensed Consolidated Statements of Income.
Also in MayNovember 2018, Southern Power entered into an equity interest purchase agreement with NextEra EnergyNorthern States Power to sell all of its equity interests in Plant Mankato (including the 385-MW expansion currently under construction) for an aggregate

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purchase price of approximately $650 million. The completion of the disposition is subject to the expansion unit reaching commercial operation as well as various other customary conditions to closing, including working capital and timing adjustments. This transaction is subject to FERC and state commission approvals. On April 17, 2019, Southern Power entered into an agreement to sell all of its equity interests in the Florida PlantsNacogdoches biomass-fueled facility to Austin Energy for an aggregate purchase price of $195$460 million, subject to customary closing conditions and working capital and timing adjustments. The ultimate purchase price will decrease $110,000 per day for each day after December 31, 2018 through the closingEach of the transaction. Conversely, the ultimate purchase price will increase $110,000 per day for each day the closing occurs prior to December 31, 2018. The salethese sales is expected to occurclose in mid-2019; however, the first half of 2019. Excluding any interest allocation for corporate debt, the pre-tax net income for the Florida Plants was $14 million and $11 million for the three months ended June 30, 2018 and 2017, respectively, and $24 million and $20 million for the six months ended June 30, 2018 and 2017, respectively. The ultimate outcome of this matterthese matters cannot be determined at this time.
Southern Power is pursuing the sale of a noncontrolling interest in a portfolio of eight operating wind facilities through the use of third-party tax equity, which, if successful, is expected to close in the fourth quarter 2018. See "Income Tax MattersLegal Entity Reorganizations" herein for additional information. The ultimate outcome of this matter cannot be determined at this time. If the transaction is completed, the tax equity partner, or partners, will have a claim to certain cash distributions and an allocation of tax attributes.
Demand for electricity is primarily driven by the pace of economic growth that may be affected by changes in regional and global economic conditions, as well as renewable portfolio standards, which may impact future earnings. Other factors that could influence future earnings include weather, transmission constraints, cost of generation from units within the power pool, and operational limitations. For additional information relating to these factors, see RISK FACTORS in Item 1A and MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL of Southern Power in Item 7 of the Form 10-K.
Power Sales Agreements
See BUSINESS – "The Southern Company System – Southern Power" in Item 1 of the Form 10-K for additional information regarding Southern Power's PPAs. Generally, under the solar and wind generation PPAs, the purchasing party retains the right to keep or resell the renewable energy credits.
At June 30, 2018, Southern Power's average investment coverage ratio for its generating assets (including the Florida Plants), based on the ratio of investment under contract to total investment using the respective generation facilities' net book value (or expected in-service value for facilities under construction and acquisitions discussed herein) as the investment amount, was 92% through 2022 and 90% through 2027, with an average remaining contract duration of approximately 15 years.

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Environmental Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Environmental Matters" of Southern Power in Item 7 of the Form 10-K for information on the development by federal and state environmental regulatory agencies of additional control strategies for emissions of air pollution from industrial sources, including electric generating facilities. Compliance with possible additional federal or state legislation or regulations related to global climate change, air quality, water quality, or other environmental and health concerns could also significantly affect Southern Power. While Southern Power's PPAs generally contain provisions that permit charging the counterparty with some of the new costs incurred as a result of changes in environmental laws and regulations, the full impact of any such legislative or regulatory changes cannot be determined at this time.
Water Quality
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Environmental Matters – Environmental Laws and Regulations – Water Quality" of Southern Power in Item 7 of the Form 10-K for additional information regarding the effluent limitations guidelines (ELG) rule.
On May 2, 2018, the EPA updated its anticipated final rulemaking schedule for ELG from September 2020 to December 2019. The impact of any changes to the ELG rule will depend on the content of the final rule and the outcome of any legal challenges and cannot be determined at this time.
FERC Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "FERC Matters" of Southern Power in Item 7 of the Form 10-K for additional information regarding proceedings related to the traditional electric operating companies' and Southern Power's 2014 and 2017 triennial market power analyses.
On May 4, 2018, the FERC issued an order terminating both proceedings, finding that the traditional electric operating companies and Southern Power satisfy the FERC's standards for market-based rates. On May 9, 2018, the traditional electric operating companies and Southern Power made the compliance filing required by the order. These proceedings are essentially concluded.
Acquisitions
During the six months ended June 30, 2018, one of Southern Power's wholly-owned subsidiaries acquired and completed construction of the Gaskell West 1 solar facility. Acquisition-related costs were expensed as incurred and were not material. See Note (J) to the Condensed Financial Statements under "Southern Power" herein and MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Southern Power in Item 7 of the Form 10-K for additional information.
Project FacilityResource
Approximate Nameplate Capacity (MW)
LocationPercentage OwnershipActual CODPPA CounterpartiesPPA Contract Period
Gaskell West 1Solar20Kern County, CA100% of Class B(*)March 2018Southern California Edison20 years
(*)Southern Power owns 100% of the class B membership interests under a tax equity partnership agreement.
The Gaskell West 1 facility did not have operating revenues or activities prior to completion of construction and the assets being placed in service during March 2018.
Construction Projects
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Acquisitions" and "Construction Projects" of Southern Power in Item 7 of the Form 10-K and FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein for additional information.
Construction Projects in Progress
During the three months ended March 31, 2019, Southern Power continued construction of the projects set forth in the table below. Total aggregate construction costs, excluding the acquisition costs, are expected to be between $575 million and $640 million for the Plant Mankato expansion and the Wildhorse Mountain and Reading facilities. At March 31, 2019, total costs of construction incurred for these projects were $347 million and are included in CWIP, except for the Plant Mankato expansion, which is included in assets held for sale in the financial statements. The ultimate outcome of these matters cannot be determined at this time.

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Construction Projects Completed and in Progress
During the six months ended June 30, 2018, Southern Power started or continued construction of the projects set forth in the table below. Total aggregate construction costs, excluding the acquisition costs, are expected to be between $520 million and $590 million for the Cactus Flats, Mankato, and Wild Horse Mountain facilities. At June 30, 2018, construction costs included in CWIP related to these projects totaled $353 million. The ultimate outcome of these matters cannot be determined at this time.
Project FacilityResource
Approximate Nameplate Capacity (MW)
Location
Actual/Expected
COD
PPA CounterpartiesPPA Contract Period
Projects Under Construction as of June 30, 2018
Cactus FlatsMankato expansion(a)
Wind148Concho County, TXJuly 2018General Motors, LLC
and
General Mills Operations, LLC
12 years
and
15 years
MankatoNatural Gas345385Mankato, MNFirst halfMay 2019Northern States Power Company20 years
Wild HorseWildhorse Mountain(b)
Wind100Pushmataha County, OKFourth quarter 2019Arkansas Electric Cooperative20 years
Reading(c)
Wind200Osage and Lyon Counties, KSSecond quarter 2020Royal Caribbean Cruises LTD12 years
(a)In July 2017,November 2018, Southern Power purchased 100%entered into an agreement to sell all of the Cactus Flats facilityits equity interests in Plant Mankato, including this expansion currently under construction. This transaction is subject to FERC and commenced construction. Subsequent to June 30, 2018, the facility was placed in servicestate commission approvals and Southern Power expectsis expected to close on a tax equity partnership agreement, which would result in Southern Power owning 100%mid-2019. The ultimate outcome of the class B membership interests.this matter cannot be determined at this time.
(b)
In May 2018, Southern Power purchased 100% of the Wild HorseWildhorse Mountain facility and commenced construction.facility. Southern Power may enter into a tax equity partnership, agreement, in which case it would then own 100% of the class B membership interests. The ultimate outcome of this matter cannot be determined at this time.
(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. described below. Southern Power may enter into a tax equity partnership, in which case it would then own 100% of the class B membership interests. The ultimate outcome of this matter cannot be determined at this time.
Development Projects
During 2017, as part of its renewable development strategy, Southern Power purchased wind turbine equipment from Siemens Gamesa Renewable Energy Inc. and Vestas-American Wind Technology, Inc. to be used for various development and construction projects. Any wind projects reaching commercial operation by 2021 are expected to qualify for 80% PTCs.
During 2016, Southern Power entered into a joint development agreement with Renewable Energy Systems Americas, Inc. to develop and construct wind projects. In addition, in 2016, Southern Power purchased wind turbine equipment from Siemens Wind Power, Inc. and Vestas-American Wind Technology, Inc. to be used for construction of the facilities. Any wind projects reaching commercial operation by 2020 are expected to qualify for 100% PTCs.
In response to the previously disclosed decrease of planned expenditures for plant acquisitions and placeholder growth, Southern Power continues to evaluate and refine the deployment of the wind turbine equipment purchased in 2016 and 2017 to potential joint development and construction projects andas well as the amount of MW capacity to be constructed. WhileDuring the expectation is that the majoritythree months ended March 31, 2019, approximately $53 million of equipment was marketed for sale and, subsequent to March 31, 2019, was sold. At March 31, 2019, the equipment will be deployed in a manner to qualifywas classified as held for the 100% and 80% PTCs,sale on Southern Power may consider other strategies, such as selling equipment or interests in projects. See FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" herein.Power's balance sheet.
The ultimate outcome of these matters cannot be determined at this time.
Income TaxOther Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Other Matters" and "Power Sales Agreements "Income Tax Matters"General" of Southern Power in Item 7 of the Form 10-K and FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk" and Note (H) to the Condensed Financial Statements herein for information regarding the Tax Reform Legislation.

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Legal Entity Reorganizations
In March 2018, Southern Power substantially completed a legal entity reorganization of various direct and indirect subsidiaries that own and operate substantially all of its solar facilities, including certain subsidiaries owned in partnership with various third parties. The reorganization resulted in net state tax benefits related to certain changes in apportionment rates totaling approximately $50 million, which were recorded in the first quarter 2018. In April 2018, Southern Power completed the final stage of the reorganization resulting in additional net state tax benefits of approximately $4 million.
Southern Power is pursuing the sale of a noncontrolling interest in a portfolio of eight operating wind facilities through the use of third-party tax equity, which, if successful, is expected to close in the fourth quarter 2018. In the third quarter 2018, various direct and indirect subsidiaries of Southern Power that own and operate these wind facilities are expected to be reorganized under a new holding company in which the tax equity partner would invest. The reorganization is expected to result in estimated net state tax benefits totaling approximately $10 million related to certain changes in apportionment rates. The ultimate outcome of this matter cannot be determined at this time.
Other Mattersinformation.
Southern Power is involved in various other matters being litigated and regulatory matters that could affect future earnings.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 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 regulatoryother business matters cannot be predicted at this time; however, for current proceedings not specifically reported in NoteNotes (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

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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 resolves both lawsuits. Under the agreement, the lawsuits will be dismissed and McCarthy will release its lien following payments of all amounts (which are expected to occur in May 2019). Roserock will pay $26 million to McCarthy that was withheld and included in the original construction costs and will receive funds that will cover all related legal costs and the replacement costs of certain solar panels. In addition, during the first quarter 2019, Roserock received a partial payment of approximately $5 million in insurance proceeds toward the hail event. Any additional funds received in excess of the initial replacement costs are expected to be recognized as a gain when received by Roserock in the second quarter 2019, but are not expected to have a material impact on Southern Power's net income.
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 NoteNotes 1, 4, and 10 to the financial statements of Southern Power in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Southern Power's results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Southern Power in Item 7 of the Form 10-K for a complete discussion of Southern Power's critical accounting policies and estimates.
Recently Issued Accounting Standards
See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Recently Issued Accounting Standards" of Southern Power in Item 7 of the Form 10-K for additional information regarding ASU No. 2016-02, Leases (Topic 842). See Note (A) to the Condensed Financial Statements herein for information regarding Southern Power's recently adopted accounting standards.

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FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Southern Power in Item 7 of the Form 10-K for additional information. Southern Power's financial condition remained stable at June 30, 2018.March 31, 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.
Southern Power also utilizes third-party tax equity partnerships, as one of the financing sources to fund its renewable growth strategy where the tax partner takes significantly all of the federal tax benefits.benefits, as a financing source. These tax equity partnerships are consolidated in Southern Power's financial statements and are accounted for using a hypothetical liquidation at book value (HLBV)HLBV methodology to allocate partnership gains and losses to Southern Power. Inlosses. During the first halfthree months of 2018,2019, Southern Power secured third-partydid not receive any material tax equity funding for the Gaskell West 1 solar project of approximately $26 million and expects to obtain tax equity funding for the Cactus Flats wind project in the third quarter 2018.amounts. See Note (A)1 to the Condensed Financial Statementsfinancial statements under "Hypothetical"Hypothetical Liquidation at Book Value" hereinValue" in Item 8 of the Form 10-K for additional information on the HLBV methodology.
In May 2018, Southern Power received approximately $1.2 billion from the sale of a 33% equity interest in SPSH, a newly-formed limited partnership indirectly owning substantially all of Southern Power's solar facilities. The proceeds were used to repay $770 million of existing indebtedness, to return capital of $250 million to Southern Company, and for other general corporate purposes, including working capital.
Southern Power is pursuing the sale of a noncontrolling interest in a portfolio of eight operating wind facilities through the use of third-party tax equity, which, if successful, is expected to close in the fourth quarter 2018. The ultimate outcome of this matter cannot be determined at this time.
Net cash provided from operating activities totaled $127$110 million for the first sixthree months of 20182019 compared to $348$149 million for the first sixthree months of 2017.2018. The decrease in net cash provided from operating activities was primarily due to a reduction in income tax payments. See FUTURE EARNINGS POTENTIAL "Income Tax Matters – Bonus Depreciation" of Southern Power in Item 7 of the Form 10-K for additional information.refunds. Net cash used for investing activities totaled $277$79 million for the first sixthree months of 20182019 primarily due to theongoing construction of generating facilities and payments for renewable acquisitions.activities. Net cash provided fromused for financing activities

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totaled $152$79 million for the first sixthree months of 20182019 primarily due to proceeds from the salepayment of a 33% equity interest in SPSH, primarily offset by debt repaymentscommon stock dividend and equity distributions.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 sixthree months of 20182019 include a $1.7$1.2 billion increase in noncontrolling interests, a $639 millionprepaid income taxes, with an offsetting $1.2 billion reduction in paid in capital, and a $298 million increase in accumulated deferred income tax assets, due to the expected utilization of tax credits for the 2019 tax year, a $372 million increase in operating lease right-of-use assets along with a corresponding increase in operating lease obligations of $371 million, due to the adoption of ASU No. 2016-02, a $68 million increase in assets held for sale due to wind turbine equipment and the continued construction of the Plant Mankato expansion, and a $66 million decrease in noncontrolling interests primarily due to HLBV income allocations to Southern Power and distributions to partners. See Note (K) under "Southern Power" and Note (L) to the sale of a 33% equity interest in SPSHCondensed Financial Statements herein for additional information on the Plant Mankato disposition and a $770 million decrease in securities due within one year due to repayments in May and June 2018.ASU No. 2016-02, respectively.
See FUTURE EARNINGS POTENTIAL "Acquisitions," "Construction Projects," and "Income Tax MattersLegal Entity Reorganizations" herein for additional information.
Capital Requirements and Contractual Obligations
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Capital Requirements and Contractual Obligations" of Southern Power in Item 7 of the Form 10-K for a description of Southern Power's capital requirements and contractual obligations. There are no scheduledApproximately $600 million will be required through March 31, 2020 to fund maturities of long-term debt through June 30, 2019.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. Subsequent to the Tax Reform Legislation, planned expenditures for plant acquisitions

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and placeholder growth are now expected to average approximately $0.5 billion per year for 2018 through 2022 and may vary materially due to market opportunities and Southern Power's ability to execute its growth strategy. Southern Power's capital expenditures for committed construction, capital improvements, and work to be performed under LTSAs remain unchanged and total approximately $0.9 billion for the five years ending 2022. Actual construction costs, 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 – "Acquisitions" and "Construction Projects" herein for additional information.
Sources of Capital
Southern Power plans to obtain the funds required for acquisitions, construction, development, debt maturities, and other purposes from operating cash flows, external securities issuances, borrowings from financial institutions, tax equity partnership contributions, divestitures, and equity contributions from Southern Company. However, the amount, type, and timing of any future financings, if needed, will depend upon prevailing market conditions, regulatory approval, and other factors. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Southern Power in Item 7 of the Form 10-K for additional information.
Southern Power's current liabilities sometimes exceed current assets due to the use of short-term debt as a funding source and construction payables, as well as fluctuations in cash needs due to seasonality. Southern Power believes the need for working capital can be adequately met by utilizing the commercial paper program, the Facility (as defined below), bank term loans, the debt capital markets,borrowings from financial institutions, equity contributions from Southern Company, external securities issuances, and operating cash flows.
As of June 30, 2018,March 31, 2019, Southern Power had cash and cash equivalents of approximately $142$133 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, and to financeincluding maturing debt. Commercial paper is included in notes payable on the condensed consolidated balance sheets.

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Details of short-term borrowings were as follows:
Short-term Debt
at June 30, 2018
 
Short-term Debt During the Period (*)
Short-term Borrowings
at March 31, 2019
 
Short-term Borrowings During the Period (*)
Amount OutstandingWeighted Average Interest Rate Average Amount Outstanding Weighted Average Interest Rate 
Maximum
Amount
Outstanding
Amount OutstandingWeighted Average Interest Rate Average Amount Outstanding Weighted Average Interest Rate 
Maximum
Amount
Outstanding
(in millions)  (in millions)   (in millions)(in millions)  (in millions)   (in millions)
Commercial paper$64
2.4% $171
 2.3% $304
$5
2.8% $3
 2.7% $45
Short-term loans200
2.7% 76
 2.6% 200
100
3.1% 100
 3.1% 100
Total$264
2.6% $247
 2.4%  $105
3.1% $103
 3.1%  
(*)Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 2018.March 31, 2019.
At June 30, 2018,March 31, 2019, Southern Power had a committed credit facility (Facility) of $750 million, of which $22$9 million has been used for letters of credit and $728$741 million remains unused. The Facility expires in 2022. Proceeds from the Facility may be used for working capital and general corporate purposes as well as liquidity support for Southern Power's commercial paper program. Subject to applicable market conditions, Southern Power expects to renew or replace the Facility, as needed, prior to expiration. In connection therewith, Southern Power may extend the maturity date and/or increase or decrease the lending commitment thereunder. See Note 68 to the financial statements of Southern Power under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.

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The Facility, as well as Southern Power's term loan agreements, contains a covenant that limits the ratio of debt to capitalization (as defined in the Facility) to a maximum of 65% and contains a cross-default provision that is restricted only to indebtedness of Southern Power. For purposes of this definition, debt excludes any project debt incurred by certain subsidiaries of Southern Power to the extent such debt is non-recourse to Southern Power, and capitalization excludes the capital stock or other equity attributable to such subsidiary. Southern Power is currently in compliance with all covenants in the Facility.
Southern Power also has a $120 million continuing letter of credit facility expiring in 20192021 for standby letters of credit. At June 30, 2018, $97March 31, 2019, $96 million has been used for letters of credit, primarily as credit support for PPA requirements, and $23$24 million remains unused.
In addition, at June 30, 2018,March 31, 2019, Southern Power had $106$103 million of cash collateral posted related to PPA requirements.
Southern Power's subsidiaries do not borrow under the commercial paper program and are not parties to, and do not borrow under, the Facility or the continuing letter of credit facility.
Credit Rating Risk
Southern Power does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change to BBB and/or Baa2, or below. These contracts are for physical electricity purchases and sales, fuel transportation and storage, energy price risk management, and transmission.

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The maximum potential collateral requirements under these contracts at June 30, 2018March 31, 2019 were as follows:
Credit RatingsMaximum Potential
Collateral
Requirements
Maximum Potential
Collateral
Requirements
(in millions)(in millions)
At BBB and/or Baa2$37
$29
At BBB- and/or Baa3$377
$339
At BB+ and/or Ba1(*)
$955
$1,041
(*)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.
As a result of the Tax Reform Legislation, certain financial metrics, such as the funds from operations to debt percentage, used by the credit rating agencies to assess Southern Company and its subsidiaries, including Southern Power, may be negatively impacted. Absent actions by Southern Power to mitigate the resulting impacts, which, among other alternatives, could include adjusting Southern Power's capital structure, Southern Power's credit ratings could be negatively affected.

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Financing Activities
In May 2018, Southern Power entered into two short-term floating rate bank loans, each for an aggregate principal amount of $100 million, which bear interest based on one-month LIBOR.
In the second quarter 2018, Southern Power used a portion of the proceeds from the sale of a 33% equity interest in SPSH to repay $420 million aggregate principal amount of long-term floating rate bank loans and $350 million aggregate principal amount of Series 2015A 1.50% Senior Notes due June 1, 2018. See Note (J) to the Condensed Financial Statements under "Southern Power – Sale of Solar Facility Interests" herein for additional information.
Southern Power received approximately $26 million of third-party tax equitydid not issue or redeem any securities during the sixthree months ended June 30, 2018 related to the Gaskell West 1 solar facility.March 31, 2019.
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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CONDENSED CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
 
For the Three Months
Ended June 30,
 For the Six Months
Ended June 30,
For the Three Months
Ended March 31,
2018 2017 2018 20172019 2018
(in millions) (in millions)(in millions)
Operating Revenues:          
Natural gas revenues (includes revenue taxes of
$23, $19, $74, and $67, respectively)
$710
 $684
 $2,341
 $2,205
Natural gas revenues (includes revenue taxes of $55 and $51, respectively)$1,476
 $1,631
Alternative revenue programs(4) 
 (27) 9
(2) (24)
Other revenues24
 32
 55
 62

 32
Total operating revenues730
 716
 2,369
 2,276
1,474
 1,639
Operating Expenses:          
Cost of natural gas228
 232
 949
 951
686
 720
Cost of other sales5
 6
 12
 13

 7
Other operations and maintenance238
 214
 514
 470
235
 276
Depreciation and amortization126
 125
 255
 244
118
 129
Taxes other than income taxes48
 44
 125
 114
82
 77
Goodwill impairment
 
 42
 

 42
Loss on disposition36
 
 36
 
Total operating expenses681
 621
 1,933
 1,792
1,121
 1,251
Operating Income49
 95
 436
 484
353
 388
Other Income and (Expense):          
Earnings from equity method investments31
 29
 74
 68
48
 42
Interest expense, net of amounts capitalized(59) (48) (118) (94)(59) (59)
Other income (expense), net3
 4
 15
 10
5
 12
Total other income and (expense)(25) (15) (29) (16)(6) (5)
Earnings Before Income Taxes24
 80
 407
 468
347
 383
Income taxes55
 31
 159
 180
77
 104
Net Income (Loss)$(31) $49
 $248
 $288
Net Income$270
 $279
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
 
 For the Three Months
Ended June 30,
 For the Six Months
Ended June 30,
 2018 2017 2018 2017
 (in millions) (in millions)
Net Income (Loss)$(31) $49
 $248
 $288
Other comprehensive income (loss):       
Qualifying hedges:       
Changes in fair value, net of tax of
$-, $(1), $-, and $(2), respectively
1
 (1) 1
 (2)
Reclassification adjustment for amounts included in net income,
net of tax of $-, $-, $1, and $-, respectively

 
 2
 
Pension and other postretirement benefit plans:       
Reclassification adjustment for amounts included in net income,
net of tax of $-, $-, $-, and $-, respectively

 
 
 (1)
Total other comprehensive income (loss)1
 (1) 3
 (3)
Comprehensive Income (Loss)$(30) $48
 $251
 $285
 For the Three Months
Ended March 31,
 2019 2018
 (in millions)
Net Income$270
 $279
Other comprehensive income (loss):   
Qualifying hedges:   
Changes in fair value, net of tax of $- and $-, respectively
 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 $- and $-, respectively
(1) (1)
Total other comprehensive income (loss)(1) 2
Comprehensive Income$269
 $281
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,
For the Three Months
Ended March 31,
2018 20172019 2018
(in millions)(in millions)
Operating Activities:      
Net income$248
 $288
$270
 $279
Adjustments to reconcile net income to net cash provided from operating activities —      
Depreciation and amortization, total255
 244
118
 129
Deferred income taxes(12) 144
42
 47
Mark-to-market adjustments2
 (49)45
 (59)
Goodwill impairment42
 

 42
Loss on disposition36
 
Other, net(24) (34)(20) (2)
Changes in certain current assets and liabilities —      
-Receivables504
 418
238
 175
-Natural gas for sale, net of temporary LIFO liquidation295
 223
363
 413
-Prepaid income taxes9
 24
-Other current assets32
 (12)59
 35
-Accounts payable(125) (102)(353) (119)
-Accrued taxes38
 (8)21
 28
-Accrued compensation(6) (12)(50) (38)
-Other current liabilities24
 25
(50) 48
Net cash provided from operating activities1,318
 1,149
683
 978
Investing Activities:      
Property additions(679) (684)(256) (268)
Cost of removal, net of salvage(18) (25)(12) (14)
Change in construction payables, net(6) 23
1
 (46)
Investment in unconsolidated subsidiaries(60) (111)(10) (29)
Disposition364
 
Other investing activities18
 18
(13) (4)
Net cash used for investing activities(381) (779)(290) (361)
Financing Activities:      
Decrease in notes payable, net(515) (631)(289) (483)
Proceeds —   
Capital contributions from parent company10
 57
Senior notes
 450
Redemptions — Gas facility revenue bonds(200) 
Payment of common stock dividends(235) (221)(118) (118)
Other financing activities
 (6)5
 6
Net cash used for financing activities(940) (351)(402) (595)
Net Change in Cash, Cash Equivalents, and Restricted Cash(3) 19
(9) 22
Cash, Cash Equivalents, and Restricted Cash at Beginning of Period78
 24
70
 78
Cash, Cash Equivalents, and Restricted Cash at End of Period$75
 $43
$61
 $100
Supplemental Cash Flow Information:      
Cash paid during the period for —   
Interest (net of $3 and $7 capitalized for 2018 and 2017, respectively)$129
 $105
Cash paid (received) during the period for —   
Interest (net of $2 and $1 capitalized for 2019 and 2018, respectively)$55
 $52
Income taxes, net106
 20
(1) 
Noncash transactions — Accrued property additions at end of period129
 84
98
 89
The accompanying notes as they relate to Southern Company Gas are an integral part of these condensed consolidated financial statements.

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CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
 
Assets At June 30, 2018 At December 31, 2017 At March 31, 2019 At December 31, 2018
 (in millions) (in millions)
Current Assets:        
Cash and cash equivalents $69
 $73
 $57
 $64
Receivables —        
Energy marketing receivables 451
 607
 529
 801
Customer accounts receivable 243
 400
 472
 370
Unbilled revenues 60
 285
 179
 213
Affiliated 9
 11
Other accounts and notes receivable 53
 103
 108
 142
Accumulated provision for uncollectible accounts (26) (28) (27) (30)
Natural gas for sale 292
 595
 189
 524
Prepaid expenses 64
 53
 99
 118
Assets from risk management activities, net of collateral 93
 135
 108
 219
Other regulatory assets, current 55
 94
Assets held for sale, current 2,298
 
Other regulatory assets 46
 73
Other current assets 42
 78
 42
 50
Total current assets 3,694
 2,395
 1,811
 2,555
Property, Plant, and Equipment:        
In service 14,504
 15,833
 15,417
 15,177
Less: Accumulated depreciation 4,293
 4,596
 4,466
 4,400
Plant in service, net of depreciation 10,211
 11,237
 10,951
 10,777
Construction work in progress 571
 491
 577
 580
Total property, plant, and equipment 10,782
 11,728
 11,528
 11,357
Other Property and Investments:        
Goodwill 5,015
 5,967
 5,015
 5,015
Equity investments in unconsolidated subsidiaries 1,507
 1,477
 1,557
 1,538
Other intangible assets, net of amortization of $121 and $120
at June 30, 2018 and December 31, 2017, respectively
 125
 280
Other intangible assets, net of amortization of $153 and $145
at March 31, 2019 and December 31, 2018, respectively
 93
 101
Miscellaneous property and investments 20
 21
 20
 20
Total other property and investments 6,667
 7,745
 6,685
 6,674
Deferred Charges and Other Assets:        
Operating lease right-of-use assets, net of amortization 86
 
Other regulatory assets, deferred 742
 901
 657
 669
Other deferred charges and assets 227
 218
 185
 193
Total deferred charges and other assets 969
 1,119
 928
 862
Total Assets $22,112
 $22,987
 $20,952
 $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, 2018 At December 31, 2017 At March 31, 2019 At December 31, 2018
 (in millions) (in millions)
Current Liabilities:        
Securities due within one year $156
 $157
 $354
 $357
Notes payable 1,003
 1,518
 361
 650
Energy marketing trade payables 485
 546
 532
 856
Accounts payable 359
 446
Accounts payable —    
Affiliated 31
 45
Other 391
 402
Customer deposits 101
 128
 91
 133
Accrued taxes —        
Accrued income taxes 86
 40
 89
 66
Other accrued taxes 63
 78
 72
 75
Accrued interest 53
 51
 64
 55
Accrued compensation 61
 74
 49
 100
Liabilities from risk management activities, net of collateral 21
 69
 26
 76
Other regulatory liabilities, current 162
 135
Liabilities held for sale, current 412
 
Other regulatory liabilities 86
 79
Other current liabilities 143
 159
 160
 130
Total current liabilities 3,105
 3,401
 2,306
 3,024
Long-term Debt 5,667
 5,891
 5,574
 5,583
Deferred Credits and Other Liabilities:        
Accumulated deferred income taxes 1,026
 1,089
 1,064
 1,016
Deferred credits related to income taxes 920
 1,063
 926
 940
Employee benefit obligations 389
 415
 351
 357
Operating lease obligations 71
 
Other cost of removal obligations 1,575
 1,646
 1,598
 1,585
Accrued environmental remediation, deferred 273
 342
Accrued environmental remediation 261
 268
Other deferred credits and liabilities 96
 118
 63
 105
Total deferred credits and other liabilities 4,279
 4,673
 4,334
 4,271
Total Liabilities 13,051
 13,965
 12,214
 12,878
Common Stockholder's Equity:    
Common stock, par value $0.01 per share —    
Authorized — 100 million shares    
Outstanding — 100 shares 
 
Paid in capital 9,236
 9,214
Accumulated deficit (202) (212)
Accumulated other comprehensive income 27
 20
Total common stockholder's equity 9,061
 9,022
Common Stockholder's Equity (See accompanying statements)
 8,738
 8,570
Total Liabilities and Stockholder's Equity $22,112
 $22,987
 $20,952
 $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
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 company14
 
 
 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
        
Balance at December 31, 2018$8,856
 $(312) $26
 $8,570
Net income
 270
 
 270
Capital contributions from parent company17
 
 
 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
The accompanying notes as they relate to Southern Company Gas are an integral part of these condensed financial statements.


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SECONDFIRST QUARTER 20182019 vs. SECONDFIRST QUARTER 2017
AND
YEAR-TO-DATE 2018 vs. YEAR-TO-DATE 2017


OVERVIEW
Southern Company Gas is an energy services holding company whose primary business is the distribution of natural gas. Subsequent to the dispositions of Elizabethtown Gas, Elkton Gas, and Florida City Gas discussed below, Southern Company Gas has natural gas distributionthrough 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 and its subsidiaries areis also involved in several other complementary businesses.
Southern Company Gas hasmanages its business through four reportable segments – gas distribution operations, gas marketing services,pipeline investments, wholesale gas services, and gas midstream operationsmarketing services – and one non-reportable segment, all other. For additional information on these segments, seeSee Note (L)(M) to the Condensed Financial Statements herein and "BUSINESS – The Southern Company System – Southern Company Gas" in Item 1 of the Form 10-K.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.
Nicor Gas filed a rate case in November 2018 and Atlanta Gas Light is required to file a rate case no later than June 3, 2019. These rate cases are both expected to conclude 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 for a total cash purchase price of $358 million and an additional $6 million for working capital. This disposition resulted in a net loss of $76 million, which included $40 million of income tax expense. In contemplation of the transaction, a goodwill impairment charge of $42 million was recorded during the first quarter 2018.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. for a total cash purchase price of $1.7 billion and an additional $40 million for working capital. This disposition resulted in an estimated pre-tax gain of approximately $235 million and an after-tax gain of approximately $12 million, which will be recorded in the third quarter 2018.
On July 29, 2018, Southern Company Gas and its wholly-owned direct subsidiary, NUI Corporation, completed the stock sale of Pivotal Utility Holdings, which primarily consisted of Florida City Gas, to NextEra Energy for a total cash purchase price of $530 million (less $3 million of indebtedness assumed at closing for customer deposits) and an additional $60 million for cash and other working capital. This disposition resulted in an estimated pre-tax gain of approximately $126 million and an after-tax gain of approximately $4 million, which will be recorded in the third quarter 2018.Energy.
The after-tax impacts of these dispositions included income tax expense on goodwill not deductible for tax purposes and for which a deferred tax liability had not been recorded previously. Additionally, each of these dispositions is subject to a final working capital adjustment that may impact the cash proceeds from disposition, but not the gain recorded. See Note (J)15 to the Condensed Financial Statementsfinancial statements in Item 8 of the Form 10-K under "Southern"Southern Company Gas" hereinGas" for additional information on these dispositions.

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Operating Metrics
Southern Company Gas continues to focus on several operating metrics, including Heating Degree Days, customer count, and volumes of natural gas sold. For additional information on these indicators, see MANAGEMENT'S DISCUSSION AND ANALYSIS – OVERVIEW – "Operating Metrics" of Southern Company Gas in Item 7 of the Form 10-K.
Southern Company Gas measures weather and the effect on its business using Heating Degree Days. Generally, increased Heating Degree Days result in higher demand for natural gas on Southern Company Gas' distribution system. With the exception of Nicor Gas, Southern Company Gas has various regulatory mechanisms, such as

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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 the gas marketing services customers primarily in Georgia and Illinois can be impacted by warmer- or colder-than-normal weather. Southern Company Gas utilizes weather hedges to reducelimit the negative earnings impactincome impacts in the event of warmer-than-normal weather, while retaining mosta significant portion of the earnings upsidepositive 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. Gas marketing services' customers are primarily located in Georgia, Illinois, and Ohio.
Southern Company Gas' natural gas volume metrics for gas distribution operations and gas marketing services illustrate the effects of weather and customer demand for natural gas. Wholesale gas services' physical sales volumes represent the daily average natural gas volumes sold to its customers.
See RESULTS OF OPERATIONS herein for additional information on these operating metrics.
Seasonality of Results
During the Heating Season, is the period from November through March when natural gas usage and operating revenues are generally higher as more customers are connected to the gas distribution systems and natural gas usage is higher in periods of colder weather. Occasionally in the summer, wholesale gas services' operating revenues are impacted due to peak usage by power generators in response to summer energy demands. Southern Company Gas' base operating expenses, excluding cost of natural gas, bad debt expense, and certain incentive compensation costs, are incurred relatively evenly throughout the year. Seasonality also affects the comparison of certain balance sheet items across quarters, including receivables, unbilled revenues, natural gas for sale, and notes payable. However, these items are comparable when reviewing Southern Company Gas' annual results. Operating results for the interim periods presented are not necessarily indicative of annual results and can vary significantly from quarter to quarter.
RESULTS OF OPERATIONS
Net Income (Loss)
Second Quarter 2018 vs. Second Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(80) (163.3) $(40) (13.9)
First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change)
$(9) (3.2)
Southern Company Gas'In the first quarter 2019, net loss for the second quarter 2018income was $31$270 million compared to net income of $49$279 million for the corresponding period in 2017. For year-to-date2018. Excluding an $8 million net loss in the first quarter 2018 net income was $248from the Southern Company Gas Dispositions, which includes the related goodwill impairment charge of $42 million compared to $288 million for the corresponding periodrecorded in 2017. The decreases were primarily due to the $36 million pre-tax loss ($76 million after tax) on the dispositioncontemplation of Pivotal Home Solutions, a reserve for a settlement of class action litigation to facilitate the sale of Pivotal Home Solutions, derivative lossesnet income decreased $17 million. This decrease was driven by a $57 million decrease at wholesale gas services disposition-relatedprimarily due to significant natural gas price volatility during the first quarter 2018. Excluding the impacts of the Southern Company Gas Dispositions and wholesale gas services, net income increased $40 million. This increase was primarily due to a $52 million increase in revenues, net of gas costs and increased interest expense. These decreases were partially offset by additional revenuesother cost recovery, primarily from infrastructure investments recovered through replacement programs less the associated increase in depreciation,and base rate changes as well as base rate changes at gas distribution operations, higher commercial activity at wholesale gas services, and revenues fromcolder weather in Illinois in the Dalton Pipeline, which was placed in service in August 2017. Also contributingfirst quarter 2019 compared to the decrease for year-to-datecorresponding period in 2018. Partially offsetting these increases were a $7 million contractor litigation settlement recorded in the first quarter 2018 and increased depreciation and amortization.

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2018 was a goodwill impairment charge of $42 million recorded during the first quarter 2018 in contemplation of the sale of Pivotal Home Solutions.
See Note (J) to the Condensed Financial Statements under "Southern Company GasSale of Pivotal Home Solutions" herein for additional information.
Natural Gas Revenues, including Alternative Revenue Programs
Second Quarter 2018 vs. Second Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$22 3.2 $100 4.5
First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change)
$(133) (8.3)
In the secondfirst quarter 2018,2019, natural gas revenues, including alternative revenue programs, were $706 million compared to $684 million for the corresponding period in 2017. For year-to-date 2018, natural gas revenues, including alternative revenue programs, were $2.3$1.5 billion compared to $2.2$1.6 billion for the corresponding period in 2017.2018.
Details of the changes in natural gas revenues, including alternative revenue programs, were as follows:
Second Quarter 2018 Year-to-Date 2018First Quarter 2019
(in millions) (% change) (in millions) (% change)(in millions) (% change)
Natural gas revenues – prior year$684



$2,214



$1,607



Estimated change resulting from –          
Infrastructure replacement programs and base rate changes38

5.6 %
48

2.2 %32

2.0
Gas costs and other cost recovery(4)
(0.6)%
(2)
(0.1)%62

3.9
Weather8

1.2 %
16

0.7 %7

0.4
Wholesale gas services(4)
(0.6)%
31

1.4 %(80)
(5.0)
Southern Company Gas Dispositions(167) (10.4)
Other(16)
(2.4)%
7

0.3 %13

0.8
Natural gas revenues – current year$706
 3.2 % $2,314
 4.5 %$1,474
 (8.3)%
The increases in natural gas revenues in the second quarter and year-to-date 2018 were primarily related to continuedRevenues from infrastructure investments recovered through replacement programs and base rate changes increased in the first quarter 2019 compared to the corresponding period in 2018 primarily due to a $22 million increase at Nicor Gas and a $9 million increase at Atlanta Gas Light. These amounts include gas distribution operations. These changes includeoperations' 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 rate cases, partially offset by revenue reductions for the impacts of the Tax Reform Legislation. See Note (B)2 to the Condensed Financial Statements hereinfinancial statements under "Regulatory Matters"Southern Company GasSouthern 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 due to reduced natural gas prices during 2018increased in the first quarter 2019 compared to the corresponding periodsperiod in 2017, partially offset by2018 primarily due to higher natural gas prices and increased volumes of natural gas sold in 2018 as a result of colder weather. See "Cost of Natural Gas" herein for additional information.
Revenues increased due to colder weather in 2018 compared to the corresponding periods in 2017 that affected the utility customers in Illinois and theremaining four natural gas marketing services customers in Georgia and Illinois. See the weather discussion herein for additional information.
Revenues from wholesale gas services decreaseddistribution utilities in the secondfirst quarter 2018 primarily due to derivative losses, partially offset by increased commercial activity and increased for year-to-date 2018 primarily due to increased commercial activity, partially offset by derivative losses. See "Wholesale Gas Services" herein for additional information.
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

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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.
Revenues increased due to colder weather in Illinois in the first quarter 2019 compared to the corresponding period in 2018. See the weather discussion herein for additional information.
Revenues from wholesale gas services decreased in the first quarter 2019 compared to the corresponding period in 2018 primarily due to decreased commercial activity, partially offset by derivative gains. See "Segment InformationWholesale Gas Services" herein for additional information.

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During Heating Season, natural gas usage and operating revenues are generally higher. Weather typically does not have a significant net income impact other than during the Heating Season. The following table presents the Heating Degree Days information for Illinois and Georgia, the primary locations where Southern Company Gas' operations are impacted by weather.
Second Quarter 2018
vs.
2017
2018
vs.
normal
 Year-to-Date 2018
vs.
2017
2018
vs.
normal
 First Quarter 2019 vs. 20182019 vs. normal
Normal(*)
20182017 colder 
Normal(*)
20182017 colder
colder
(warmer)
 
Normal(*)
20192018 colder (warmer)
Illinois628
767
555
 38.2%22.1% 3,698
3,809
3,110
 22.5%3.0 % 3,045
3,297
3,042
 8.4 %8.3 %
Georgia122
175
75
 133.3%43.4% 1,578
1,539
1,000
 53.9%(2.5)% 1,441
1,213
1,364
 (11.1)%(15.8)%
(*)Normal represents the 10-year average from January 1, 20082009 through June 30, 2017March 31, 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, which limited the negative incomeservices. The remaining impacts of weather on earnings are reflected in the chart below.
Gas Distribution Operations Gas Marketing ServicesGas Distribution Operations Gas Marketing Services
Second Quarter Year-to-Date Second Quarter Year-to-DateFirst Quarter First Quarter
20182017 20182017 20182017 2018201720192018 20192018
(in millions) (in millions)(in millions) (in millions)
Pre-tax$4
$1
 $2
$(5) $2
$(3) $(1)$(10)$2
$(2) $
$(3)
After tax3
1
 2
(3) 1
(2) (1)(6)2
(2) 
(2)
The following table provides the number of customers served by Southern Company Gas at June 30, 2018March 31, 2019 and 2017:2018:
June 30,  March 31,  
2018 2017 2018 vs. 20172019 2018 2019 vs. 2018
(in thousands, except market share %) (% change)(in thousands, except market share %) (% change)
Gas distribution operations(a)
4,609
 4,573
 0.8 %4,276
 4,654
 (8.1)%
Gas marketing services(b)
          
Energy customers(c)(b)
696
 768
 (9.4)%701
 779
 (10.0)%
Market share of energy customers in Georgia29.4% 29.1% 

28.8% 29.2% 

(a)
Includes total customers of approximately 407,000 and 403,000 at June 30,March 31, 2018 and 2017, respectively, related to Elizabethtown Gas, Elkton Gas, and Florida City Gas, which were sold subsequent to June 30,in July 2018. See Note (J)15 to the Condensed Financial Statements under "Southern Company GasSalefinancial statements in Item 8 of Elizabethtown Gas and Elkton Gas" and " – Sale of Florida City Gas" herein for additional information.
(b)On June 4, 2018, Southern Company Gas completed the sale of Pivotal Home Solutions, which served approximately 1.2 million contracts prior to disposition. See Note (J) to the Condensed Financial StatementsForm 10-K under "Southern Company Gas – Sale of Pivotal Home Solutions" hereinGas" for additional information.
(c)(b)The decrease at June 30, 2018 isGas marketing services' customers are primarily due to approximately 70,000 fewerlocated in Georgia and Illinois. Also included are customers in Ohio contracted through an annual auction process to serve for 12 months beginning April 1 2018.of each year. At June 30, 2017,March 31, 2019 and 2018, there were approximately 70,000 and 140,000 contracted customers, in Ohio contracted through an annual auction process to serve for 12 months beginning April 1, 2017.respectively.

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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.

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Other Revenues
First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change)
$(32) (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 2018 vs. Second Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(4) (1.7) $(2) (0.2)
First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change)
$(34) (4.7)
NaturalExcluding 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 84%87% of total cost of natural gas for bothin the secondfirst quarter and year-to-date 2018. For additional information, see2019. See MANAGEMENT'S DISCUSSION AND ANALYSIS – RESULTS OF OPERATIONS – "Cost of Natural Gas and Other Sales"Gas" of Southern Company Gas in Item 7 of the Form 10-K and "Natural Gas Revenues, including Alternative Revenue Programs" herein.herein for additional information.
In the secondfirst quarter 2018,2019, cost of natural gas was $228$686 million compared to $232$720 million for the corresponding period in 2017. The2018. Excluding a $79 million decrease related to the Southern Company Gas Dispositions that resulted in a decrease in the volume of natural gas sold as a result of fewer gas distribution operations customers, cost of natural gas increased $45 million. This increase reflects a 12% decrease4.9% increase in natural gas prices during the second quarter 2018 compared to the corresponding period in 2017, partially offset byand an increase in the volume of natural gas sold in 2018the first quarter 2019 primarily as a result of colder weather.
For year-to-date 2018, cost of natural gas was $949 million compared to $951 million for the corresponding periodweather in 2017. The decrease reflects an 11% decrease in natural gas prices during year-to-date 2018Illinois compared to the corresponding period in 2017, partially offset by an increase in volumes of natural gas sold in 2018 as a result of colder weather.
The following table details the volumes of natural gas sold during all periods presented.
 Second Quarter2018
vs.
2017
 Year-to-Date2018
vs.
2017
 20182017 20182017
Gas distribution operations (mmBtu in millions)
      
Firm119
102
16.7% 434
365
18.9 %
Interruptible25
23
8.7% 49
48
2.1 %
Total144
125
15.2% 483
413
16.9 %
Gas marketing services (mmBtu in millions)
 
   
Firm:  

   

Georgia5
4
25.0% 22
17
29.4 %
Illinois2
2
% 8
7
14.3 %
Ohio2
2
% 11
5
120.0 %
Other1
1
% 2
3
(33.3)%
Interruptible large commercial and industrial3
3
% 7
7
 %
Total13
12
8.3% 50
39
28.2 %
Wholesale gas services (mmBtu in millions/day)
 

   

Daily physical sales6.4
6.2
3.2% 6.6
6.4
3.1 %
2018.

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The following table details the volumes of natural gas sold during all periods presented.
 First Quarter2019
vs.
2018
 20192018
Gas distribution operations (mmBtu in millions)
   
Firm296
314
(5.7)%
Interruptible25
25
 %
Total(*)
321
339
(5.3)%
Wholesale gas services (mmBtu in millions/day)
   
Daily physical sales7.0
6.8
2.9 %
Gas marketing services (mmBtu in millions)
  
Firm:  

Georgia15
16
(6.3)%
Illinois6
6
 %
Other8
10
(20.0)%
Interruptible large commercial and industrial4
4
 %
Total33
36
(8.3)%
(*)
Includes total volumes of natural gas sold of 26 mmBtu for the three months ended March 31, 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
First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change)
$(7) (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 2018 vs. Second Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$24 11.2 $44 9.4
First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change)
$(41) (14.9)
In the secondfirst quarter 2018,2019, other operations and maintenance expenses were $238$235 million compared to $214$276 million for the corresponding period in 2017. The increase was primarily due2018. Excluding a $29 million decrease related to an $11 million reserve for a settlement of class action litigation to facilitate the sale of Pivotal Home Solutions, a $6 million increase in compensation and benefit costs, and $4 million of disposition-related costs.
For year-to-date 2018,Southern Company Gas Dispositions, other operations and maintenance expenses were $514 million compared to $470 million for the corresponding period in 2017. The increasedecreased $12 million. This decrease was primarily due to an $11 million reserve for a settlement of class action litigation to facilitateone-time adjustment in the sale of Pivotal Home Solutions, a $22 million increase in compensation and benefit costs, a $12 million one-time increasefirst quarter 2018 for the adoption of a new paid time off policy to align with the Southern Company system, and $6 million of disposition-related costs. These increases were partially offset by an $8 million decrease in recoverable costs, primarily related to bad debt expense, at gas distribution operations. See Notes (B) and (J) to the Condensed Financial Statements under "General Litigation Matters – Southern Company Gas" and "Southern Company Gas – Sale of Pivotal Home Solutions," respectively, herein for additional information.policy. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL "Other Matters" of Southern Company Gas in Item 7 of the Form 10-K for additional information on the new paid time off policy.information.
Depreciation and Amortization
Second Quarter 2018 vs. Second Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$1 0.8 $11 4.5
In the second quarter 2018, depreciation and amortization was $126 million compared to $125 million for the corresponding period in 2017. For year-to-date 2018, depreciation and amortization was $255 million compared to $244 million for the corresponding period in 2017. These increases were primarily due to continued infrastructure investments recovered through replacement programs at gas distribution operations, partially offset by timing of amortization of intangible assets as a result of fair value adjustments in acquisition accounting at gas marketing services and ceasing recognition of depreciation and amortization on Pivotal Home Solutions' assets classified as held for sale and subsequently sold in the second quarter 2018.
Taxes Other Than Income Taxes
Second Quarter 2018 vs. Second Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$4 9.1 $11 9.6
In the second quarter 2018, taxes other than income taxes were $48 million compared to $44 million for the corresponding period in 2017. For year-to-date 2018, taxes other than income taxes were $125 million compared to $114 million for the corresponding period in 2017. These increases primarily reflect an increase in revenue tax expenses as a result of higher revenues as well as payroll taxes related to benefits under the new paid time off policy.
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Other Matters" of Southern Company Gas in Item 7 of the Form 10-K for additional information on the new paid time off policy.

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Depreciation and Amortization
First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change)
$(11) (8.5)
In the first quarter 2019, depreciation and amortization was $118 million compared to $129 million for the corresponding period in 2018. Excluding a $16 million decrease related to the Southern Company Gas Dispositions, depreciation and amortization increased $5 million. This increase was primarily due to continued infrastructure investments at gas distribution operations.
Taxes Other Than Income Taxes
First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change)
$5 6.5
In the first quarter 2019, taxes other than income taxes were $82 million compared to $77 million for the corresponding period in 2018. Excluding a $3 million decrease related to the Southern Company Gas Dispositions, taxes other than income taxes increased $8 million. This increase primarily reflects increases in Nicor Gas' invested capital tax and revenue tax expenses as a result of higher natural gas revenues at Nicor Gas, both of which are passed through directly to customers.
Goodwill Impairment
First Quarter 2019 vs. First Quarter 2018
Second Quarter 2018 vs. Second Quarter 2017Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions)(% change)(change in millions) (% change)
$(42) N/A$42N/AM
N/AM - Not applicablemeaningful
For year-to-dateIn the first quarter 2018, a goodwill impairment charge of $42 million was recorded during the first quarter 2018 in contemplation of the sale of Pivotal Home Solutions. See Note (A)15 to the Condensed Financial Statementsfinancial 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
First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change)
$6 14.3
Goodwill and Other Intangible Assets" andIn the first quarter 2019, earnings from equity method investments were $48 million compared to $42 million for the corresponding period in 2018. This increase was primarily due to higher earnings from SNG as a result of rate increases implemented by SNG that became effective September 2018. See Note (J)(E) to the Condensed Financial Statements under "Southern Company GasSale of Pivotal Home Solutions" herein for additional information.
Loss on DispositionOther Income (Expense), Net
Second Quarter 2018 vs. Second Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$36 N/A $36 N/A
First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change)
$(7) (58.3)
N/A - Not applicable
The sale of Pivotal Home Solutions was structured as a stock sale for book purposes; however, both parties elected to treat it as an asset sale for tax purposes. The resulting increase in the book loss is offset by a reduction in deferred tax expense. See "Income Taxes" herein and Note (J) to the Condensed Financial Statements under "Southern Company Gas – Sale of Pivotal Home Solutions" herein for additional information.
Earnings from Equity Method Investments
Second Quarter 2018 vs. Second Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$2 6.9 $6 8.8
In the secondfirst quarter 2018, earnings from equity method investments were $312019, other income (expense), net was $5 million compared to $29$12 million for the corresponding period in 2017. The increase2018. This decrease was primarily due to higher earnings from SNG. For year-to-date 2018, earnings from equity method investments were $74 million compared to $68 million fora contractor litigation settlement in the corresponding period in 2017. The increase was primarily due to higher earnings from SNG.
Interest Expense, Net of Amounts Capitalized
Second Quarter 2018 vs. Second Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$11 22.9 $24 25.5
In the secondfirst quarter 2018 interest expense, net of amounts capitalized was $59 million compared to $48 million for the corresponding period in 2017. For year-to-date 2018, interest expense, net of amounts capitalized was $118 million compared to $94 million for the corresponding period in 2017. These increases were primarily due to additional interest expense on new debt issuances and additional commercial paper borrowings as well as a reduction in capitalized interest due to the Dalton Pipeline being placed in service in August 2017.. See

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Other 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 (Expense), NetTaxes
Second Quarter 2018 vs. Second Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$(1) (25.0) $5 50.0
First Quarter 2019 vs. First Quarter 2018
(change in millions) (% change)
$(27) (26.0)%
For year-to-date 2018, otherIn the first quarter 2019, income (expense), net was $15taxes were $77 million compared to $10$104 million for the corresponding period in 2017. The increase was primarily due to2018. Excluding a $7$13 million gain from the settlement of a contractor litigation claim, partially offset by a decrease in interest income. See Note (B)related to the Condensed Financial Statements under "Regulatory Matters – Southern Company GasAtlanta Gas Light's Pipeline Replacement Program" herein for additional information.
Income Taxes
Second Quarter 2018 vs. Second Quarter 2017 Year-to-Date 2018 vs. Year-to-Date 2017
(change in millions) (% change) (change in millions) (% change)
$24 77.4 $(21) (11.7)
In the second quarter 2018, Dispositions, income taxes were $55 million compared to $31 million for the corresponding period in 2017. The increase was primarily due to $40 million of income taxes associated with the sale of Pivotal Home Solutions, primarily due to goodwill not deductible for tax purposes and for which a deferred tax liability had not been recorded previously, partially offset by the reduction in deferred tax expense as a result of treating the sale as an asset sale for tax purposes. In addition, this increase was partially offset by lower pre-tax earnings as well as a lower federal income tax rate and the flowback of excess deferred taxes as a result of the Tax Reform Legislation.
For year-to-date 2018, income taxes were $159 million compared to $180 million for the corresponding period in 2017. Thedecreased $14 million. This decrease was primarily due to lower pre-tax earnings as well as a lower federal income tax ratecompared to the prior year and an increase in the flowback of excess deferred taxes as a result of the Tax Reform Legislation. This decrease was partially offset by $40 million of income taxes recorded forin 2019 primarily at Atlanta Gas Light as previously authorized by the sale of Pivotal Home Solutions which includes the reduction in deferred tax expense as a result of treating the sale as an asset sale for tax purposes.
Georgia PSC. See Notes (H) and (J)Note (G) to the Condensed Financial Statements herein under "Effective Tax Rate" and "Southern"Southern Company Gas – Sale of Pivotal Home Solutions," respectively, hereinGas" 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, and 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 marketing services,pipeline investments, wholesale gas services, and gas midstream operationsmarketing services allows it to focus on a direct measure of adjusted operating marginperformance 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.
 First Quarter 2019 First Quarter 2018
 (in millions)
Operating Income$353
 $388
Other operating expenses(a)
435
 524
Revenue taxes(b)
(54) (50)
Adjusted Operating Margin$734
 $862
(a)Includes other operations and maintenance expenses, depreciation and amortization, taxes other than income taxes, and goodwill impairment.
(b)Nicor Gas' revenue tax expenses, which are passed through directly to customers.

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 Second Quarter 2018Second Quarter 2017 Year-to-Date 2018Year-to-Date 2017
 (in millions)
Operating Income$49
$95
 $436
$484
Other operating expenses(a)
448
383
 972
828
Revenue taxes(b)
(23)(18) (73)(65)
Adjusted Operating Margin$474
$460
 $1,335
$1,247
(a)Includes other operations and maintenance, depreciation and amortization, taxes other than income taxes, goodwill impairment, and loss on disposition.
(b)Nicor Gas' revenue tax expenses, which are passed through directly to customers.
Segment Information
Adjusted operating margin, operating expenses, and net income for each segment is illustratedare provided in the tablestable below. See Note (L)(M) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information.
Second Quarter 2018
Second Quarter 2017First Quarter 2019
First Quarter 2018

 Adjusted Operating Margin(a)
 
Operating Expenses(a)(b)
 
Net Income (Loss)(b)
 
Adjusted Operating Margin(a)
 
Operating Expenses(a)
 Net Income (Loss)
 Adjusted Operating Margin(a)
 
Operating Expenses(a)
 Net Income (Loss) 
Adjusted Operating Margin(a)
 
Operating Expenses(a)(b)
 
Net Income (Loss)(b)
(in millions) (in millions)(in millions) (in millions)
Gas distribution operations$429

$296

$68

$409

$284

$54
$524

$314

$133

$557

$323

$149
Gas pipeline investments8

3

32

8

3

27
Wholesale gas services84

19

47

163

22

104
Gas marketing services48

87

(76)
57

48

4
115

31

61

128

95

13
Wholesale gas services(16)
14

(21)
(13)
14

(17)
Gas midstream operations13

14

14

7

13

9
All other1

15

(16)
3

9

(1)6

17

(3)
9

34

(14)
Intercompany eliminations(1)
(1)


(3)
(3)

(3)
(3)


(3)
(3)

Consolidated$474
 $425
 $(31) $460
 $365
 $49
$734
 $381
 $270
 $862
 $474
 $279
(a)Adjusted operating margin and operating expenses are adjusted for Nicor GasGas' revenue tax expenses, which are passed through directly to customers.
(b)
Operating expenses and net income for gas distribution operations and gas marketing services include the loss on disposition. Net loss for gas marketing services includesimpacts of the loss on disposition of assets and the associated income tax expense.Southern Company Gas Dispositions. See Note (J)15 to the Condensed Financial Statementsfinancial statements in Item 8 of the Form 10-K under "Southern"Southern Company GasSale of Pivotal Home Solutions" hereinGas" for additional information.

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 Year-to-Date 2018 Year-to-Date 2017
 
 Adjusted Operating Margin(a)
 
Operating Expenses(a)(b)(c)
 
Net Income (Loss)(c)
 
Adjusted Operating Margin(a)
 
Operating Expenses(a)
 Net Income
 (in millions) (in millions)
Gas distribution operations$986

$620

$216

$951

$599

$171
Gas marketing services175

181

(63)
162

101

35
Wholesale gas services147

36

83

118

29

51
Gas midstream operations29

29

38

16

25

25
All other2

37

(26)
5

14

6
Intercompany eliminations(4)
(4)


(5)
(5)

Consolidated$1,335
 $899
 $248
 $1,247
 $763
 $288
(a)Adjusted operating margin and operating expenses are adjusted for Nicor Gas revenue tax expenses, which are passed through directly to customers.
(b)
Operating expenses for gas marketing services include a goodwill impairment charge of $42 million recorded during the first quarter 2018 in contemplation of the sale of Pivotal Home Solutions. See Note (A) to the Condensed Financial Statements under "Goodwill and Other Intangible Assets" and Note (J) to the Condensed Financial Statements under "Southern Company GasSale of Pivotal Home Solutions" herein for additional information.
(c)
Operating expenses for gas marketing services include the loss on disposition. Net loss for gas marketing services includes the loss on disposition and the associated income tax expense. See Note (J) to the Condensed Financial Statements under "Southern Company GasSale of Pivotal Home Solutions" herein for additional information.
Gas Distribution Operations
Gas distribution operations is the largest component of Southern Company Gas' business and is subject to regulation and oversight by agencies in each of the states it serves. These agencies approve natural gas rates designed to provide Southern Company Gas with the opportunity to generate revenues to recover the cost of natural gas delivered to its customers and its fixed and variable costs, including depreciation, interest, 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 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.
SecondIn 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. 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.
First Quarter 20182019 vs. SecondFirst Quarter 20172018
In the secondfirst quarter 2018,2019, net income increased $14decreased $16 million, or 25.9%10.7%, compared to the corresponding period in 2017.2018. This increasedecrease primarily relates to an increase of $20a $33 million decrease in adjusted operating margin and a $7 million decrease in other income tax expense of $11 million, partially offset by an increase of $12 million in operating expenses and an increase of $5 million in interest expense,(expense), net, of amounts capitalized. The increase in adjusted operating margin primarily reflects $39 million in additional revenue from continued infrastructure investments recovered through replacement programs and base rates. The decrease in income taxes is primarily due to a lower federal income tax rate and the flowback of excess deferred taxes as a result of the Tax Reform Legislation. The increase in operating expenses primarily reflects additional depreciation due to additional assets placed in service and increased compensation and benefit costs, partially offset by a decrease of $16 million in recoverable costs, primarily related to bad debt expense. The increaseincome tax expense and a $9 million decrease in interest expense includes the impact of the issuance of first mortgage bonds at Nicor Gas in 2017 and additional commercial paper borrowings during the second quarter 2018.operating expenses.

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Year-to-Date 2018 vs. Year-to-Date 2017
For year-to-date 2018, net income increased $45Excluding an $89 million or 26.3%, compareddecrease attributable to the corresponding period in 2017. This increase primarily relates to an increase of $35 million inutilities sold during 2018, adjusted operating margin an increase of $4increased $56 million, in other income (expense), net, and a decrease in income tax expense of $38 million, partially offset by an increase of $21 million in operating expenses and an increase of $11 million in interest expense, net of amounts capitalized. The increase in adjusted operating marginwhich primarily reflects $86 million in additional revenue from continued infrastructure investments recovered through infrastructure replacement programs and base rates, partially offset by revenue deferrals totaling $38 million for regulatory liabilities associated withrate increases, the Tax Reform Legislation impacts. The increaseeffect of revenues deferred in other income (expense), net primarily reflects a gain from the settlement of a contractor litigation claim in 2018 partially offset by a decrease in interest income. The decrease in income taxes is primarily due to a lower federal income tax rate and the flowback of excess deferred taxes as a result of the Tax Reform Legislation. The increaseLegislation, and colder weather in Illinois during the first quarter 2019 compared to the corresponding period in 2018. Excluding a $40 million decrease attributable to the utilities sold during 2018, operating expenses primarily reflectsincreased $31 million, which includes increased compensation and benefit costs, higher expenses passed through directly to customers, increased expenses for storage facilities, and additional depreciation primarily due to additional assets placed in service and increased compensation and benefit costs, partially offset by aservice. The decrease in recoverable costs, primarily relatedother income (expense), net is due to bad debt expense. The increasea contractor litigation settlement in the first quarter 2018. Excluding $6 million of interest expense includesattributable to the impact ofutilities sold during 2018, interest expense increased $7 million primarily from the issuance of first mortgage bonds at Nicor GasGas. Excluding a $12 million decrease attributable to the utilities sold in 2017 and additional commercial paper borrowings during year-to-date 2018.2018, income tax expense decreased $4 million, primarily due to an increase in the flowback of excess deferred income taxes in 2019, partially offset by higher pre-tax earnings.
Gas Marketing ServicesPipeline Investments
Gas marketing servicespipeline investments consists primarily of several businesses that provide energy-related products and services tojoint ventures in natural gas markets,pipeline investments including warranty sales. Gas marketing services is weather sensitiveSNG, Atlantic Coast Pipeline, PennEast Pipeline, 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 completed50% joint ownership interest in the sale of Pivotal Home Solutions to American Water Enterprises LLC.Dalton Pipeline. See Note (J) under "Southern Company Gas"(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.
SecondFirst Quarter 2019 vs. First Quarter 2018 vs. Second Quarter 2017
In the secondfirst quarter 2018,2019, net income decreased $80increased $5 million, or 18.5%, compared to the corresponding period in 2017.2018. This decrease was drivenincrease primarily relates to a $6 million increase in earnings from equity method investments largely due to higher earnings from SNG, partially offset by a $76$2 million loss on the sale of Pivotal Home Solutions, which included $40 million ofincrease in income tax expense on goodwill not deductible for tax purposes and for which a deferred tax liability had not been recorded previously and an $11 million pre-tax reserve for a settlement of class action litigation to facilitate the sale of Pivotal Home Solutions. See Notes (B) and (J) to the Condensed Financial Statements under "General Litigation Matters – Southern Company Gas" and "Southern Company Gas – Sale of Pivotal Home Solutions," respectively, herein for additional information.
Year-to-Date 2018 vs. Year-to-Date 2017
For year-to-date 2018, net income decreased $98 million compared to the corresponding period in 2017. This decrease was driven by a $76 million loss on the sale of Pivotal Home Solutions, which included $40 million of income tax expense on goodwill not deductible for tax purposes and for which a deferred tax liability had not been recorded previously, a $42 million goodwill impairment charge recorded in contemplation of the sale of Pivotal Home Solutions, and an $11 million pre-tax reserve for a settlement of class action litigation to facilitate the sale of Pivotal Home Solutions, partially offset by an increase in adjusted operating margin of $13 million, a decrease in depreciation and amortization of $10 million, primarily due to the timing of amortization of intangible assets as a result of fair value adjustments recorded during acquisition accounting as well as the sale of Pivotal Home Solutions, and a decrease in the federal income tax rate. Adjusted operating margin increased by $13 million due to $9 million for colder weather in 2018, $6 million for fixed and guaranteed bill revenue as a result of adopting a new revenue recognition standard, and $2 million from energy customers contracted through an annual auction process to serve for 12 months beginning April 1, 2017, partially offset by the sale of Pivotal Home Solutions during the second quarter 2018. See Note (A) under "Recently Adopted Accounting Standards" and "Goodwill and Other Intangible Assets," Note (B) under "General Litigation Matters – Southern Company Gas," and Note (J) under "Southern Company Gas – Sale of Pivotal Home Solutions" to the Condensed Financial Statements herein for additional information.

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higher pre-tax earnings.
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.
SecondFirst Quarter 20182019 vs. SecondFirst Quarter 20172018
In the secondfirst quarter 2018,2019, net income decreased $4$57 million, or 23.5%54.8%, compared to the corresponding period in 2017.2018. This decrease was primarily due to interest incurred on a promissory note issued during 2018 to meet working capital needs.
Year-to-Date 2018 vs. Year-to-Date 2017
For year-to-date 2018, net income increased $32 million, or 62.7%, compared to the corresponding period in 2017. This increase primarily relates to a $29$79 million increasedecrease in adjusted operating margin, andpartially offset by a decrease of $11$19 million in income tax expense partially offset by an increase of $7and a $3 million decrease in operating expenses. Details of the increasedecrease in adjusted operating margin are provided in the table below. The increasedecrease in operating expenses primarily reflects higherlower compensation and benefit expense. The decrease in income tax expense was driven by a lower federal income tax rate, partially offset by higher pretaxpre-tax earnings.

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Second Quarter 2018Second Quarter 2017 Year-to-Date 2018Year-to-Date 2017First Quarter 2019First Quarter 2018
(in millions)(in millions)
Commercial activity recognized$17
$(18) $189
$69
$38
$172
Gain (loss) on storage derivatives
17
 1
18
Gain on storage derivatives3
2
Gain (loss) on transportation and forward commodity derivatives(28)(2) (44)37
29
(16)
LOCOM adjustments, net of current period recoveries
(1) (3)(1)(2)(3)
Purchase accounting adjustments to fair value inventory and contracts(5)(9) 4
(5)16
8
Adjusted operating margin$(16)$(13) $147
$118
$84
$163
Change in Commercial Activity
The increase in 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 positive commercial activity recognized in the secondfirst quarter and year-to-date 2018 compared to the corresponding periods in 20172019 was primarily due to natural gas price volatility that resulted from intermittent cold weather throughout the period. The decrease in commercial activity in the first quarter 2019 compared to the corresponding period in 2018 was generated by favorableprimarily due to significant natural gas price volatility that resulted from prolonged cold weather and a corresponding increase in power generation volumesduring the first quarter 2018 coupled with decreasedlow natural gas supply.
Change in Storage and Transportation Derivatives
Volatility in the natural gas market arises from a number of factors, such as weather fluctuations or changes in supply or demand for natural gas in different regions of the U.S. The volatility of natural gas commodity prices has a significant impact on Southern Company Gas' customer rates, long-term competitive position against other energy sources, and the ability of wholesale gas services to capture value from locational and seasonal spreads. Forward storage or time spreads applicable to the locations of wholesale gas services' specific storage positions in 2018 remained consistent with the 2017 spreads.2019 resulted in storage derivative gains. Transportation and forward commodity derivative lossesgains in 20182019 are primarily the result of wideningnarrowing transportation spreads due to favorable weather,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.

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Withdrawal Schedule and Physical Transportation Transactions
The expected natural gas withdrawals from storage and expected offset to prior hedge losses/gains associated with the transportation portfolio of wholesale gas services are presented in the following table, along with the net operating revenues expected at the time of withdrawal from storage and the physical flow of natural gas between contracted transportation receipt and delivery points. Wholesale gas services' expected net operating revenues exclude storage and transportation demand charges, as well as other variable fuel, withdrawal, receipt, and delivery charges, and exclude estimated profit sharing under asset management agreements. Further, the amounts that are realizable in future periods are based on the inventory withdrawal schedule, planned physical flow of natural gas between the transportation receipt and delivery points, and forward natural gas prices at June 30, 2018.March 31, 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.

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 Storage withdrawal schedule  
 
Total storage(a)
 
Expected net operating gains(b)
 
Physical transportation transactions – expected net operating gains(c)
 (in mmBtu in millions) (in millions) (in millions)
201825.9
 $4
 $10
2019 and thereafter9.0
 4
 34
Total at June 30, 201834.9
 $8
 $44
 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)
20197
 $1
 $(6)
2020 and thereafter1
 1
 (23)
Total at March 31, 20198
 $2
 $(29)
(a)At June 30, 2018,March 31, 2019, the WACOG of wholesale gas services' expected natural gas withdrawals from storage was $2.51$2.24 per mmBtu.
(b)Represents expected operating gains from planned storage withdrawals associated with existing inventory positions and could change as wholesale gas services adjusts its daily injection and withdrawal plans in response to changes in future market conditions and forward NYMEX price fluctuations.
(c)Represents the periods associated with the transportation derivative gains and (losses) during which the derivativeslosses that will be settled during the period and the physical transportation transactions will occur that offset the derivative gains and losses that were previously recognized.
The unrealized storage and transportation derivative gains do not change the underlying economic value of wholesale gas services' storage and transportation positions and will be reversed when the related transactions occur and are recognized. For more information on wholesale gas services' energy marketing and risk management activities, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Market Price Risk" of Southern Company Gas in Item 7 of the Form 10-K.
Gas Midstream OperationsMarketing Services
Gas midstream operations consists primarilymarketing 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 gas pipeline investments, with storagehedging strategies, such as weather derivative instruments and fuels also aggregated into this segment.other risk management tools, to partially mitigate potential weather impacts.
On June 4, 2018, Southern Company Gas pipeline investments include SNG, Horizon Pipeline, Atlantic Coast Pipeline, PennEast Pipeline, Dalton Pipeline, and Magnolia Enterprise Holdings, Inc.completed the sale of Pivotal Home Solutions to American Water Enterprises LLC. See Note (K) to the Condensed Financial Statements herein and Note 415 to the financial statements of Southern Company Gas in Item 8 of the Form 10-K under "Southern Company Gas" for additional information.
SecondFirst Quarter 20182019 vs. SecondFirst Quarter 20172018
In the secondfirst quarter 2018,2019, net income increased $5$48 million or 55.6%, compared to the corresponding period in 2017.2018. This increase primarily relates to a $6$64 million increasedecrease in operating expenses, partially offset by a $13 million decrease in adjusted operating margin primarily due to the Dalton Pipeline being placed in service in August 2017 and a $2 million net increase in earnings from equity method investments in SNG, PennEast Pipeline, and Horizon Pipeline, partially offset by an increase in interest expense due to lower amounts capitalized after the Dalton Pipeline was placed in service.
Year-to-Date 2018 vs. Year-to-Date 2017
For year-to-date 2018, net income increased $13 million, or 52.0%, compared to the corresponding period in 2017. This increase primarily relates to a $13$3 million increase in income tax expense.
Excluding a $25 million decrease attributable to the 2018 disposition of Pivotal Home Solutions, adjusted operating margin increased $12 million, which primarily duereflects favorable margins and recovery of prior period hedge losses. Excluding a $61 million decrease attributable to the Dalton

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Pipeline being placed in service in August 2017, lower costs atPivotal Home Solutions that includes the storage facilities, and a $6 million net increase in earnings from equity method investments in SNG, PennEast Pipeline, and Horizon Pipeline, partially offset by an increase in interestrelated goodwill impairment charge, operating expense due to lower interest capitalized after the Dalton Pipeline was placed in service.decreased $3 million.
All Other
All other includes Southern Company Gas' storage and fuels operations and its investment in Triton, AGL Services Company, and Southern Company Gas Capital, as well as various corporate operating expenses that are not allocated to the reportable segments and interest income (expense) associated with affiliate financing arrangements.
SecondFirst Quarter 20182019 vs. SecondFirst Quarter 20172018
In the secondfirst quarter 2018,2019, net incomeloss decreased $15$11 million compared to the corresponding period in 2017.2018. This decrease primarily reflects a $6an $17 million increasedecrease in operating expenses, that includes $4partially offset by a $3 million of disposition-related costs, a $2 million increasedecrease in interest expense, net of amounts capitalized primarily due to new debt issuances and additional commercial paper borrowings, and a $4 million increase in income taxes due to tax allocation changes.
Year-to-Date 2018 vs. Year-to-Date 2017
For year-to-date 2018, net income decreased $32 million compared to the corresponding period in 2017. Thisadjusted operating margin. The decrease primarily reflects a $23 million increase in operating expenses and a $6 million increase in interest expense. The increase in operating expenses primarily reflects a $12 million increaseone-time adjustment in compensation expense resulting from the adoption of the new paid time off policy and $6 million of disposition-related costs. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Other Matters" of Southern Company Gas in Item 7 of the Form 10-K for additional information on the new paid time off policy. The increase in interest expense was primarily associated with new debt issuances and additional commercial paper borrowings.
Segment Reconciliations
Reconciliations of operating income to adjusted operating margin for the second quarter 2018 and 2017 are reflected in the following tables. See Note (L) to the Condensed Financial Statements herein for additional information.

Second Quarter 2018

Gas Distribution OperationsGas Marketing ServicesWholesale Gas ServicesGas Midstream OperationsAll OtherIntercompany EliminationConsolidated

(in millions)
Operating Income (Loss)$133
$(39)$(30)$(1)$(14)$
$49
Other operating expenses(a)
319
87
14
14
15
(1)448
Revenue tax expense(b)
(23)




(23)
Adjusted Operating Margin$429
$48
$(16)$13
$1
$(1)$474

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compensation expense in the first quarter 2018 for the adoption of a new paid time off policy and a decrease in depreciation and amortization. The decrease in adjusted operating margin primarily relates to a decrease in storage revenues.
 Second Quarter 2017
 Gas Distribution OperationsGas Marketing ServicesWholesale Gas ServicesGas Midstream OperationsAll OtherIntercompany EliminationConsolidated
 (in millions)
Operating Income (Loss)$125
$9
$(27)$(6)$(6)$
$95
Other operating expenses(a)
302
48
14
13
9
(3)383
Revenue tax expense(b)
(18)




(18)
Adjusted Operating Margin$409
$57
$(13)$7
$3
$(3)$460
Segment Reconciliations
Reconciliations of operating income to adjusted operating margin for the first quarter 2019 and 2018 are reflected in the following tables. See Note (M) to the Condensed Financial Statements herein for additional information.
Year-to-Date 2018First Quarter 2019
Gas Distribution OperationsGas Marketing ServicesWholesale Gas ServicesGas Midstream OperationsAll OtherIntercompany EliminationConsolidatedGas Distribution OperationsGas Pipeline InvestmentsWholesale Gas ServicesGas Marketing ServicesAll OtherIntercompany EliminationConsolidated
(in millions)(in millions)
Operating Income (Loss)$366
$(6)$111
$
$(35)$
$436
$210
$5
$65
$84
$(11)$
$353
Other operating expenses(a)
693
181
36
29
37
(4)972
368
3
19
31
17
(3)435
Revenue tax expense(b)
(73)




(73)(54)




(54)
Adjusted Operating Margin$986
$175
$147
$29
$2
$(4)$1,335
$524
$8
$84
$115
$6
$(3)$734
Year-to-Date 2017First Quarter 2018
Gas Distribution OperationsGas Marketing ServicesWholesale Gas ServicesGas Midstream OperationsAll OtherIntercompany EliminationConsolidatedGas Distribution OperationsGas Pipeline InvestmentsWholesale Gas ServicesGas Marketing ServicesAll OtherIntercompany EliminationConsolidated
(in millions)(in millions)
Operating Income (Loss)$352
$61
$89
$(9)$(9)$
$484
$234
$5
$141
$33
$(25)$
$388
Other operating expenses(a)
664
101
29
25
14
(5)828
373
3
22
95
34
(3)524
Revenue tax expense(b)
(65)




(65)(50)




(50)
Adjusted Operating Margin$951
$162
$118
$16
$5
$(5)$1,247
$557
$8
$163
$128
$9
$(3)$862
(a)Includes other operations and maintenance expenses, depreciation and amortization, taxes other than income taxes, and goodwill impairment, and loss on disposition.impairment.
(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 first quarter 2018,net income attributable to these dispositions, excluding the related goodwill impairment, was $34 million.The level of Southern Company Gas' future earnings depends on numerous factors that affect the opportunities, challenges, and risks of Southern Company Gas' primary business of natural gas distribution and its complementary businesses in the gas marketing services,pipeline investments, wholesale gas services, and gas midstream operationsmarketing services sectors. These factors include Southern Company Gas' ability to maintain a constructive regulatory environmentenvironments that allowsallow for the timely recovery of prudently-incurred costs, the completion and subsequent operation of ongoing infrastructure and other construction projects, creditworthiness of customers, its ability to optimize its transportation and storage positions, and its ability to re-contract storage rates at favorable prices.
Future earnings will be driven by customer growth and are subject to a variety of other factors. These factors include weather, competition, new energy contracts with other utilities and other wholesale customers, energy conservation practiced by customers, the use of alternative energy sources by customers, the price of natural gas, the price elasticity of demand, and the rate of economic growth or decline in Southern Company Gas' service territories.

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Demand for natural gas is primarily driven by the pace of economic growth that may be affected by changes in regional and global economic conditions, which may impact future earnings.
Volatility of natural gas prices has a significant impact on Southern Company Gas' customer rates, 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.
On June 4, 2018, Southern Company Gas completed the stock sale of Pivotal Home Solutions to American Water Enterprises LLC. For year-to-date 2018, net income attributable to Pivotal Home Solutions, exclusive of the loss on the disposition and the related goodwill impairment charge, was immaterial. Southern Company Gas and American Water Enterprises LLC entered into a transition services agreement whereby Southern Company Gas will provide certain administrative and operational services through no later than February 3, 2019.
On July 1, 2018, a Southern Company Gas subsidiary, Pivotal Utility Holdings, completed the sales of the assets of two of its natural gas distribution utilities, Elizabethtown Gas and Elkton Gas, to South Jersey Industries, Inc. For year-to-date 2018, net income attributable to Elizabethtown Gas and Elkton Gas was $26 million. However, dueDue to the seasonal nature of the natural gas business and other factors including, but not limited to, weather, regulation, competition, customer demand, and general economic conditions, the year-to-date 2018 net income isfirst quarter 2019 results are not necessarily indicative of the results to be expected for any other period. Southern Company Gas and South Jersey Industries, Inc. entered into transition services agreements whereby Southern Company Gas will provide certain administrative and operational services through no later than January 31, 2020.
On July 29, 2018, Southern Company Gas and its wholly-owned direct subsidiary, NUI Corporation, completed the stock sale of Pivotal Utility Holdings, which primarily consisted of Florida City Gas, to NextEra Energy. For year-to-date 2018, net income attributable to Florida City Gas was $8 million. However, due to the seasonal nature of the natural gas business and other factors including, but not limited to, weather, regulation, competition, customer demand, and general economic conditions, the year-to-date 2018 net income is not necessarily indicative of the results to be expected for any other period. Southern Company Gas and NextEra Energy entered into a transition services agreement whereby Southern Company Gas will provide certain administrative and operational services through no later than July 29, 2020.
See Note (J) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information on these dispositions. See OVERVIEW "Seasonality of Results" for additional information on seasonality.
Environmental Matters
New or revised environmental laws and regulations could affect many areas of Southern Company Gas' operations. The impact of any such changes cannot be determined at this time. Environmental compliance costs could affect earnings if such costs cannot continue to be fully recovered in rates on a timely basis. Further, increased costs that are recovered through regulated rates could contribute to reduced demand for natural gas, which could negatively affect results of operations, cash flows, andand/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 (B) under "Environmental Matters

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Environmental Remediation"(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 of Southern Company Gas under "Environmental Matters"Remediation" in Item 8 of the Form 10-K for additional information.
Regulatory Matters
See Note 32 to the financial statements of Southernunder "Southern Company Gas under "Regulatory Matters"Gas" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory MattersSouthern Company Gas" herein for additional information regarding Southern Company Gas' regulatory matters.
RidersRate Proceedings
On April 19,Nicor Gas
In November 2018, Nicor Gas filed a general base rate case with the Illinois Commission approved Nicor Gas' variable income tax adjustment rider. This rider provides for refund or recovery of changesrequesting a $230 million increase in income tax expense that result from income tax rates that differ from those used in Nicor Gas' last rate case. Customer refunds began on July 1, 2018 related to the January 1, 2018 through May 4, 2018 impacts of the Tax Reform Legislation. The impact of the Tax Reform Legislation subsequent to May 4, 2018 was addressed in Nicor Gas' approved rehearing request discussed herein under "Settled Base Rate Cases."
Natural Gas Cost Recovery
Southern Company Gas has established natural gas cost recovery rates approved by the relevant state regulatory agencies in the states in which it serves. Natural gas cost recovery revenues are adjusted for differences in actual recoverable natural gas costs and amounts billed in current regulated rates. Changes in the billing factor will not have a significant effect on Southern Company Gas' revenues or net income, but will affect cash flows.
Base Rate Cases
Settled Base Rate Cases
On February 23, 2018, Atlanta Gas Light revised its annual base rate filing to reflect the impacts of the Tax Reform Legislation andrevenues. The requested a $16 million rate reduction in 2018. On May 15, 2018, the Georgia PSC approved a stipulation for Atlanta Gas Light's annual base rates to remain at the 2017 level for 2018 and 2019, with customer credits of $8 million in each of July 2018 and October 2018 to reflect the impacts of the Tax Reform Legislation. The Georgia PSC maintained Atlanta Gas Light's previously authorized earnings bandincrease is based on a projected test year for the 12-month period ending September 30, 2020, a ROE between 10.55%of 10.6%, and 10.95% and increasedan increase in the allowed equity ratio by 4%from 52% to an equity ratio of 55%54% to address the negative cash flow and credit metric impacts of the Tax Reform Legislation. Additionally, Atlanta Gas Light is required to file a traditional base rate case on or before June 1, 2019 for rates effective January 1, 2020.
On May 2, 2018,April 16, 2019, Nicor Gas entered into a stipulation agreement to resolve all related issues with the Staff of the Illinois Commission, approved Nicor Gas' rehearing request for revised base rates to incorporate the reduction in the federal income tax rate as a result of the Tax Reform Legislation. The resulting decrease of approximately $44 million in annual base rate revenues became effective May 5, 2018. Nicor Gas' previously-authorized capital structure and ROE of 9.8% were not addressed in the rehearing and remain unchanged. The impact of the Tax Reform Legislation prior to May 5, 2018 was addressed in the variable income tax rider discussed herein under "Riders."
Pending Base Rate Case
On February 15, 2018, Chattanooga Gas filed a general base rate case with the Tennessee Public Utility Commission (PUC) requesting a $7 million increase in annual base rate revenues. The requested increase, which, in accordance with a Tennessee PUC order, incorporated the effects of the Tax Reform Legislation, was based on a projected test year ending June 30, 2019 andincluding a ROE of 11.25%9.86% and an equity ratio of 54%. The Tennessee PUC is expected to ruleAlso on April 16, 2019, Nicor Gas filed its rebuttal testimony with the requested increase inIllinois Commission incorporating the third quarter 2018.
The ultimate outcome of this matter cannot be determined at this time.stipulation agreement and addressing the

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Otherremaining 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 VirginiaIllinois Commission issued an orderis expected to rule on the requested increase within the statutory time limit of 11 months from the filing of the rate case, after which rate adjustments will be effective. The ultimate outcome of this matter cannot be determined at this time.
Atlanta Gas Light
Atlanta Gas Light is required to file a traditional base rate case no later than June 3, 2019 for rates effective January 1, 2020.
Virginia Natural Gas
In December 2018, that requires utilities in the stateVirginia Commission approved Virginia Natural Gas' annual information form filing, which reduced annual base rates by $14 million effective January 1, 2019 due to deferlower 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 impactbalance 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 Tax Reform Legislation, including the reductionnatural 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 corporate income tax rate to 21% and the impactfirst three months of the flowback of excess deferred income taxes.2019 were as follows:
UtilityProgramFirst Quarter 2019
  (in millions)
Nicor GasInvesting in Illinois$29
Virginia Natural GasSteps to Advance Virginia's Energy (SAVE)9
Total $38
On April 25, 2018,8, 2019, Virginia Natural Gas filed an application with the Virginia Commission issued an order indicating that anyto amend and extend its SAVE program. The proposal beyond a proposed base rate reduction to reflect the cost savings from the Tax Reform Legislation must be made through a general base rate case.would allow Virginia Natural Gas expects to addresscontinue replacing aging pipeline infrastructure and increase its authorized investment under the cost savingscurrently-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 Tax Reform Legislationplan 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 third quarter 2018 by filing an annual information form.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 impact ofrequest in the Tax Reform Legislation by the first half ofthird quarter 2019. The ultimate outcome of this matter cannot be determined at this time.
Asset Management Agreements
Upon closing the sales of Elizabethtown Gas and Elkton Gas, an affiliate of South Jersey Industries, Inc. assumed the asset management agreements with wholesale gas services for Elizabethtown Gas and Elkton Gas. See Note (J) to the Condensed Financial Statements under "Southern Company Gas" herein for additional information on these dispositions. For additional information, see MANAGEMENT'S DISCUSSION AND ANALYSIS – FUTURE EARNINGS POTENTIAL – "Regulatory Matters Asset Management Agreements" of Southern Company Gas in Item 7 of the Form 10-K.
Regulatory Infrastructure Programs
Southern Company Gas is engaged in various infrastructure programs that update or expand its gas distribution systems to improve reliability and help ensure the safety of its utility infrastructure and recovers in rates its investment and a return associated with these infrastructure programs. Excluding the natural gas distribution utilities sold subsequent to June 30, 2018, infrastructure expenditures incurred in the first six months of 2018 were as follows:
UtilityProgramYear-to-Date 2018
  (in millions)
Nicor GasInvesting in Illinois$135
Atlanta Gas LightGeorgia Rate Adjustment Mechanism (GRAM) infrastructure spending139
Virginia Natural GasSteps to Advance Virginia's Energy24
Total $298
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Regulatory Matters Infrastructure Replacement Programs and Capital Projects" of Southern Company Gas in Item 7 and Note 32 to the financial statements of Southernunder "Southern Company Gas under "Regulatory Matters Regulatory Infrastructure Programs"Replacement Programs and Capital Projects" in Item 8 of the Form 10-K for additional information.
Income Tax
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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 the new agreement to have a material impact on its financial statements.
FERC Matters
See MANAGEMENT'S DISCUSSION AND ANALYSIS FUTURE EARNINGS POTENTIAL "Income Tax "FERC Matters" of Southern Company Gas in Item 7 of the Form 10-K and FINANCIAL CONDITION AND LIQUIDITY – "Credit Rating Risk," Note (B)Notes 7 and 9 to the Condensed Financial Statementsfinancial statements under "Regulatory Matters"Southern Company GasEquity Method Investments" and "Guarantees," respectively, in Item 8 of the Form 10-K for additional information regarding Southern Company Gas," and Note (H) to the Condensed Financial Statements herein for information regarding the Tax Reform Legislation and related regulatory actions.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 for additional information.
Southern Company Gas is involved in various other matters being litigated and regulatory matters that could affect future earnings.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 ultimate outcome of such pending or potential litigation, or regulatory matters,

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or potential asset impairments cannot be predicted at this time; however, for current proceedings not specifically reported in NoteNotes (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 NoteNotes (B) and (C) to the Condensed Financial Statements herein for a discussion of various other contingencies, and regulatory matters, and other matters being litigated which may affect future earnings potential.
Southern Company Gas owns a 50% interest in a planned LNG liquefaction and storage facility in Jacksonville, Florida. Once construction is complete and the facility is operational, it will be outfitted with a 2.0 million gallon storage tank with the capacity to produce in excess of 120,000 gallons of LNG per day. It is expected to be operational in the third quarter 2018. The ultimate outcome of this matter cannot be determined at this time.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
Southern Company Gas prepares its financial statements in accordance with GAAP. Significant accounting policies are described in NoteNotes 1, 5, and 6 to the financial statements of Southern Company Gas in Item 8 of the Form 10-K. In the application of these policies, certain estimates are made that may have a material impact on Southern Company Gas' results of operations and related disclosures. Different assumptions and measurements could produce estimates that are significantly different from those recorded in the financial statements. See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Application of Critical Accounting Policies and Estimates" of Southern Company Gas in Item 7 of the Form 10-K for a complete discussion of Southern Company Gas' critical accounting policies and estimates.
Recently Issued Accounting Standards
See MANAGEMENT'S DISCUSSION AND ANALYSIS – ACCOUNTING POLICIES – "Recently Issued Accounting Standards" of Southern Company Gas in Item 7 of the Form 10-K for additional information regarding ASU No. 2016-02, Leases (Topic 842). See Note (A) to the Condensed Financial Statements herein for information regarding Southern Company Gas' recently adopted accounting standards.
FINANCIAL CONDITION AND LIQUIDITY
Overview
See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Overview" of Southern Company Gas in Item 7 of the Form 10-K for additional information. Southern Company Gas' financial condition remained stable at June 30, 2018.March 31, 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.

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By regulation, Nicor Gas is restricted, to the extent of its retained earnings balance, in the amount it can dividend or loan to affiliates and is not permitted to make money pool loans to affiliates. Prior to the disposition of Elizabethtown Gas, the New Jersey BPU restricted the amount Elizabethtown Gas could dividend to its parent company to 70% of its quarterly net income. At June 30, 2018,March 31, 2019, the amount of subsidiary retained earnings and net income restricted to dividend totaled $796$875 million. These restrictionsThis restriction did not have any impact on Southern Company Gas' ability to meet its cash obligations. Subsequent to the disposition of Elizabethtown Gas, management does not expect the remaining restriction to materially impact Southern Company Gas' ability to meet its currently anticipated cash obligations.
Net cash provided from operating activities totaled $1.3 billion$683 million for the first sixthree months of 2018, an increase2019, a decrease of $169$295 million from the corresponding period in 2017.2018. The increasedecrease was primarily due to increased volumesthe impacts of natural gas sold during the first six monthsSouthern Company Gas Dispositions and the timing of 2018 as a result of colder weather compared to the prior year, partially offset by higher income taxvendor payments. Net cash used for investing activities totaled $381$290 million for the first sixthree months of 20182019 primarily due to gross property additions related to utility capital expenditures forand infrastructure investments

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recovered through replacement programs at gas distribution operations and capital contributed to equity method investments in pipelines, partially offset by proceeds from the disposition of Pivotal Home Solutions.pipeline investments. Net cash used for financing activities totaled $940$402 million for the first sixthree months of 20182019 primarily due to net repayments of commercial paper borrowings the redemption of gas facility revenue bonds, and a common stock dividend payment to Southern Company. Cash flows from financing activities vary from period to period based on capital needs and the maturity or redemption of securities.
Significant balance sheet changes for the first sixthree months of 20182019 include the reclassification of $2.3 billion and $412 million in total assets and liabilities held for sale, respectively, associated with Elizabethtown Gas, Elkton Gas, and Florida City Gas as described in Note (J) to the Condensed Financial Statements herein under "Southern Company Gas" and "Assets Held for Sale," a decrease of $295$363 million in natural gas for sale, net of temporary LIFO liquidation, due to the use of stored natural gas and a $515$289 million decrease in notes payable primarily related to net repayments of commercial paper borrowings. Other significant balance sheet changes include decreases of $71 million in accounts payable as well as $156$272 million and $61$324 million in energy marketing receivables and payables, respectively, due to lower natural gas prices and volumes of natural gas sold, and an increase of $462$171 million in total property, plant, and equipment primarily due to utility capital expenditures for rate base investments and pre-approved rider and infrastructure investments recovered through replacement programs. Balance sheet changes for the first three months of 2019 also include recording $86 million in operating lease right-of use assets and $84 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. Approximately $155$350 million will be required through June 30, 2019March 31, 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 32 to the consolidated financial statements of Southernunder "Southern Company GasGas" 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 throughfrom sources similar to those used in the past, which were primarily from operating cash flows, external securities issuances, borrowings from financial institutions, and borrowings and equity contributions from Southern Company. In addition, Southern Company Gas plans to utilize the proceeds from the dispositions of Elizabethtown Gas, Elkton Gas, Florida City Gas, and Pivotal Home Solutions to pay the income taxes resulting from the sales, to retire existing debt, and for general corporate purposes. However, the amount, type, and timing of any future financings, if needed, depend upon prevailing market conditions, regulatory approval, and other factors. The issuance of securities by Nicor Gas is generally subject to the approval of the Illinois Commission. See MANAGEMENT'S DISCUSSION AND ANALYSIS – FINANCIAL CONDITION AND LIQUIDITY – "Sources of Capital" of Southern Company Gas in Item 7 of the Form 10-K for additional information.
The assets and liabilities associated with Elizabethtown Gas, Elkton Gas, and Florida City Gas are classified as held for sale and recorded as current assets and liabilities on the balance sheet at June 30, 2018 as described in Note (J) to the Condensed Financial Statements herein under "Southern Company Gas" and "Assets Held for Sale." Excluding the assets and liabilities classified as held for sale, Southern Company Gas' current liabilities exceeded current assets by $1.3 billion$495 million primarily as a result of $1.0 billion$361 million in notes payable.payable and $354 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. Southern Company Gas

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intends to utilize operating cash flows, external securities issuances,liabilities frequently exceed current assets because of commercial paper borrowings from financial institutions, borrowings and equity contributions from Southern Company, and the proceeds from its dispositionsused to fund its short-term capital needs. Southern Company Gas has substantialdaily operations, scheduled maturities of long-term debt, and significant seasonal fluctuations in cash flow from operating activities and access to the capital markets and financial institutions to meet liquidity needs.
At June 30, 2018,March 31, 2019, Southern Company Gas had $69$57 million of cash and cash equivalents. Committed credit arrangements with banks at June 30, 2018March 31, 2019 were as follows:
CompanyExpires 2022 Unused
 (in millions)
Southern Company Gas Capital(a)
$1,400
 $1,395
Nicor Gas500
 500
Total(b)
$1,900
 $1,895
(a)Southern Company Gas guarantees the obligations of Southern Company Gas Capital.
(b)Pursuant to the credit arrangement, the allocations between Southern Company Gas Capital and Nicor Gas may be adjusted.
See Note 68 to the consolidated financial statements of Southern Company Gas under "Bank Credit Arrangements" in Item 8 of the Form 10-K and Note (F) to the Condensed Financial Statements under "Bank Credit Arrangements" herein for additional information.
The multi-year credit arrangement of Southern Company Gas Capital and Nicor Gas (Facility) contains a covenant that limits the ratio of debt to capitalization (as defined in the Facility) to a maximum of 70% for each of Southern Company Gas and Nicor Gaslevels and contains a cross-acceleration provision to other indebtedness (including guarantee obligations) of the applicable company. Such cross-acceleration provision to other indebtedness would trigger an event of default of the applicable company if Southern Company Gas or Nicor Gas defaulted on indebtedness, the payment of which was then accelerated. At June 30, 2018,March 31, 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. Commercial paperShort-term borrowings are included in notes payable in the balance sheets.
Details of short-term borrowings were as follows:
Short-Term Debt at
June 30, 2018
 
Short-Term Debt During the Period(a)
Short-Term Debt at
March 31, 2019
 
Short-Term Debt During the Period(*)
Amount
Outstanding
 Weighted Average Interest Rate Average Amount Outstanding Weighted Average Interest Rate Maximum Amount OutstandingAmount
Outstanding
 Weighted Average Interest Rate Average Amount Outstanding Weighted Average Interest Rate Maximum Amount Outstanding
Commercial paper:(in millions)   (in millions)   (in millions)(in millions)   (in millions)   (in millions)
Southern Company Gas Capital$573
 2.4% $709
 2.4% $855
$326
 2.8% $364
 2.9% $472
Nicor Gas154
 2.3% 104
 2.2% 180
35
 2.6% 106
 2.9% 247
Short-term loans:         
Southern Company Gas(b)
276
 2.8% 111
 2.7% 276
Total$1,003
 2.5% $924
 2.4%  $361
 2.8% $470
 2.9%  
(a)(*)Average and maximum amounts are based upon daily balances during the three-month period ended June 30, 2018.March 31, 2019.
(b)Subsequent to June 30, 2018, Southern Company Gas repaid all $276 million of short-term loans.
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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Southern Company Gas believes the need for working capital can be adequately met by utilizing commercial paper programs, lines of credit, and operating cash flows.
Additionally, Pivotal Utility Holdings redeemed five series of gas facility revenue bonds issued under loan agreements with the New Jersey Economic Development Authority and Brevard County, Florida totaling $200 million during the second quarter 2018. See "Financing Activities" herein for additional information regarding the redemption of these bonds.
Credit Rating Risk
Southern Company Gas does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade.
There are certain contracts that could require collateral, but not accelerated payment, in the event of a credit rating change below BBB- and/or Baa3. These contracts are for physical gas purchases and sales and energy price risk management. The maximum potential collateral requirement under these contracts at June 30, 2018March 31, 2019 was approximately $10$12 million.
Generally, collateral may be provided by a Southern Company guaranty, letter of credit, or cash. Additionally, a credit rating downgrade could impact the ability of Southern Company Gas to access capital markets and would be likely to impact the cost at which it does so.
As a result of the Tax Reform Legislation, certain financial metrics, such as the funds from operations to debt percentage, used by the credit rating agencies to assess Southern Company and its subsidiaries, including Southern Company Gas, may be negatively impacted. Southern Company Gas and certain of its regulated subsidiaries are takinghave 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 32 to the financial statements of Southernunder "Southern Company Gas under "Regulatory Matters"Gas" in Item 8 of the Form 10-K and Note (B) to the Condensed Financial Statements under "Regulatory MattersSouthern Company Gas" herein for information on additional information.rate proceedings for Nicor Gas and Atlanta Gas Light expected to conclude 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, 2018,March 31, 2019, the non-principal components totaled $483$444 million, which consisted of the unamortized portions of the fair value adjustment recorded in purchase accounting, debt premiums, debt discounts, and debt issuance costs.
On January 4, 2018, Southern Company Gas issued a floating rate promissory note to Southern Company in an aggregate principal amount of $100 million bearing interest based on one-month LIBOR. Ondid not issue or redeem any securities during the three months ended March 28, 2018, Southern Company Gas repaid this promissory note.
In the second quarter 2018, Pivotal Utility Holdings caused $200 million aggregate principal amount of gas facility revenue bonds to be redeemed. Also in the second quarter 2018, Pivotal Utility Holdings, as borrower, and Southern Company Gas, as guarantor, entered into a $181 million short-term delayed draw floating rate bank term loan bearing interest based on one-month LIBOR, which Pivotal Utility Holdings used to repay the gas facility revenue bonds. Subsequent to June 30, 2018, Pivotal Utility Holdings repaid this short-term loan.
In May 2018, Southern Company Gas Capital borrowed $95 million pursuant to a short-term uncommitted bank credit arrangement, guaranteed by Southern Company Gas, bearing interest at a rate agreed upon by Southern Company Gas Capital and the bank from time to time and payable on no less than 30 days' demand by the bank. The proceeds of the loan were used to pay down short-term debt. Subsequent to June 30, 2018, Southern Company Gas Capital repaid this loan.

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Subsequent to June 30, 2018, Nicor Gas agreed to issue $300 million aggregate principal amount of first mortgage bonds in a private placement, $100 million of which is expected to be issued in August 2018 and $200 million of which is expected to be issued in November 2018.31, 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 secondfirst quarter 2018.2019. 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 (D)(I) and (I)(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 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

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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 2018Second Quarter 2017 Year-to-Date 2018Year-to-Date 2017First Quarter 2019First Quarter 2018
(in millions)(in millions)
Contracts outstanding at beginning of period, assets (liabilities), net$(70)$64
 $(106)$12
$(167)$(106)
Contracts realized or otherwise settled2
(20) 51
(16)(5)49
Current period changes(a)
(22)7
 (35)55
44
(13)
Contracts outstanding at the end of period, assets (liabilities), net$(90)$51

$(90)$51
$(128)$(70)
Netting of cash collateral183
71
 183
71
190
223
Cash collateral and net fair value of contracts outstanding at end of period(b)
$93
$122

$93
$122
$62
$153
(a)Current period changes also include the fair value of new contracts entered into during the period, if any.
(b)Net fair value of derivative contracts outstanding excludes premium and the intrinsic value associated with weather derivatives of $3$11 million and $4 million at June 30,March 31, 2019 and 2018, and includes premium and the intrinsic value associated with weather derivatives of $11 million at June 30, 2017.respectively.

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The maturities of Southern Company Gas' energy-related derivative contracts at June 30, 2018March 31, 2019 were as follows:
  Fair Value Measurements  Fair Value Measurements
  June 30, 2018  March 31, 2019
Total
Fair Value
 MaturityTotal
Fair Value
 Maturity
 Year 1  Years 2 & 3 Years 4 and thereafter Year 1  Years 2 & 3 Years 4 and thereafter
(in millions)(in millions)
Level 1(a)
$(135) $(24) $(77) $(34)$(144) $(36) $(76) $(32)
Level 2(b)
45
 13
 33
 (1)35
 26
 10
 (1)
Fair value of contracts outstanding at end of period(c)
$(90) $(11) $(44) $(35)
Level 3(c)
(19) 2
 (2) (19)
Fair value of contracts outstanding at end of period(d)
$(128) $(8) $(68) $(52)
(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 $183$190 million as well as premium and associated intrinsic value associated with weather derivatives of $3$11 million at June 30, 2018.March 31, 2019.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS
FOR
THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
ALABAMA POWER COMPANY
GEORGIA POWER COMPANY
GULF POWER COMPANY
MISSISSIPPI POWER COMPANY
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES
(UNAUDITED)


INDEX TO THE NOTES TO THE CONDENSED FINANCIAL STATEMENTS
Note Page Number
A
B
C
D
D
E
F
G
H
H
I
J
JK
K
L
M





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.
RegistrantApplicable Notes
Southern CompanyA, B, C, D, E, F, G, H, I, J, K, L, M
Alabama PowerA, B, C, D, F, G, H, I, J, L
Georgia PowerA, B, C, D, F, G, H, I,
Gulf PowerA, B, C, D, F, G, H, I, J, L
Mississippi PowerA, B, C, D, F, G, H, I, J, L
Southern PowerA, C, D, E, F, G, H, I, J, K, L
Southern Company GasA, B, C, D, E, F, G, H, I, J, K,
Southern Company GasA, B, C, D, F, G, H, I, J, K, L, M


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THE SOUTHERN COMPANY AND SUBSIDIARY COMPANIES
ALABAMA POWER COMPANY
GEORGIA POWER COMPANY
GULF POWER COMPANY
MISSISSIPPI POWER COMPANY
SOUTHERN POWER COMPANY AND SUBSIDIARY COMPANIES
SOUTHERN COMPANY GAS AND SUBSIDIARY COMPANIES

NOTES TO THE CONDENSED FINANCIAL STATEMENTS:
(UNAUDITED)

(A)INTRODUCTION
(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, 20172018 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, 2018March 31, 2019 and 2017.2018. 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
See Note 1 to the financial statements of the registrants under "Recently Issued Accounting Standards" in Item 8 of the Form 10-K for additional information.
Revenue
In 2014,2016, the FASB issued ASC 606,ASU No. 2016-02, Revenue from Contracts with CustomersLeases (Topic 842) (ASC 606), replacing the existing accounting standard and industry-specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the standard is(ASU 2016-02). ASU 2016-02 requires lessees to recognize revenueon 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 depict the transfer of goods or services to customers ataccounting for existing leveraged leases. The registrants adopted the amount expected to be collected. ASC 606 becamenew standard effective on January 1, 20182019. See Note (L) for additional information and the registrants adopted it using the modified retrospective method applied to open contracts and only to the versionrelated disclosures.

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Table of the contracts in effect as of January 1, 2018. In accordance with the modified retrospective method, the registrants' previously issued financial statements have not been restated to comply with ASC 606 and the registrants did not have a cumulative-effect adjustment to retained earnings. The adoption of ASC 606 had no significant impact on the timing of revenue recognition compared to previously reported results; however, it requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers, which are included in Note (C).Contents

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

ASC 606 provided additional clarity on financial statement presentation that resulted in reclassifications into other revenues and other operations and maintenance from other income/(expense), net at Alabama Power and Georgia Power related to certain unregulated sales of products and services. In addition, contract assets related to Southern Company's unregulated distributed generation business have been reclassified from unbilled revenue in accordance with the guidance in ASC 606. These reclassifications did not affect the timing or amount of revenues recognized or cash flows. ASC 606 also provided additional guidance on over-time revenue recognition, resulting in a change in the timing of revenue recognized from guaranteed and fixed billing arrangements at Southern Company Gas. The changes in natural gas revenues recognized in the second quarter and year-to-date 2018 relate primarily to the seasonal nature of natural gas usage.
The net impact of accounting for revenue under ASC 606 decreased Southern Company's consolidated net income by $5 million for the three months ended June 30, 2018 and increased Southern Company's consolidated net income by $5 million for the six months ended June 30, 2018.
The specific impacts of applying ASC 606 to revenues from contracts with customers on the financial statements of Southern Company, Alabama Power, Georgia Power, and Southern Company Gas compared to previously recognized guidance is shown below.

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

 For the Three Months Ended
June 30, 2018
 For the Six Months Ended
June 30, 2018
Condensed Statements of IncomeAs ReportedBalances Without Adoption of
ASC 606
Effect of Change As Reported
Balances Without Adoption of
ASC 606
Effect of Change
 (in millions) (in millions)
Southern Company       
Natural gas revenues$706
$713
$(7) $2,314
$2,307
$7
Other revenues395
393
2
 808
805
3
Other operations and maintenance1,559
1,546
13
 3,008
2,985
23
Operating income63
81
(18) 1,439
1,452
(13)
Other income (expense), net78
67
11
 138
118
20
Earnings (loss) before income taxes(266)(259)(7) 784
777
7
Income taxes (benefit)(139)(137)(2) (25)(27)2
Consolidated net income (loss)(127)(122)(5) 809
804
5
Consolidated net income (loss) attributable to Southern Company(154)(149)(5) 784
779
5
        
Alabama Power       
Other revenues$69
$60
$9
 $131
$114
$17
Other operations and maintenance402
391
11
 788
767
21
Operating income380
382
(2) 752
756
(4)
Other income (expense), net12
10
2
 15
11
4
        
Georgia Power       
Other revenues$120
$97
$23
 $227
$189
$38
Other operations and maintenance457
437
20
 863
828
35
Operating income (loss)(472)(475)3
 41
38
3
Other income (expense), net35
38
(3) 73
76
(3)
        
Southern Company Gas       
Natural gas revenues$710
$717
$(7) $2,341
$2,334
$7
Operating income49
56
(7) 436
429
7
Earnings before income taxes24
31
(7) 407
400
7
Income taxes55
57
(2) 159
157
2
Net income (loss)(31)(26)(5) 248
243
5

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

 For the Six Months Ended
June 30, 2018
Condensed Statements of Cash FlowsAs Reported
Balances Without Adoption of
ASC 606
Effect of Change
 (in millions)
Southern Company   
Consolidated net income$809
$804
$5
Changes in certain current assets and liabilities:   
Receivables94
99
(5)
Other current assets(40)(45)5
Accrued taxes213
215
(2)
Other current liabilities125
118
7
    
Georgia Power   
Changes in certain current assets and liabilities:   
Receivables$(103)$(75)$(28)
Other current assets25
(3)28
    
Southern Company Gas   
Net income$248
$243
$5
Changes in certain current assets and liabilities:   
Accrued taxes38
40
(2)
Other current liabilities24
17
7
 At June 30, 2018
Condensed Balance SheetsAs Reported
Balances Without Adoption of
ASC 606
Effect of Change
 (in millions)
Southern Company   
Unbilled revenues$769
$824
$(55)
Other accounts and notes receivable621
622
(1)
Other current assets172
116
56
Accrued taxes544
542
2
Other current liabilities808
815
(7)
Retained earnings8,494
8,489
5
    
Southern Company Gas   
Accrued income taxes$86
$84
$2
Other current liabilities143
150
(7)
Accumulated deficit(202)(207)5
Other
In 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (ASU 2016-18). ASU 2016-18 eliminates the need to reflect transfers between cash and restricted cash in operating, investing, and financing activities in the statements of cash flows. In addition, the net change in cash and cash

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

equivalents during the period includes amounts generally described as restricted cash or restricted cash equivalents. The registrants adopted ASU 2016-18 effective January 1, 2018 with no material impact on their financial statements. Southern Company, Southern Power, and Southern Company Gas retrospectively applied ASU 2016-18 effective January 1, 2018 and have restated prior periods in the statements of cash flows by immaterial amounts. The change in restricted cash in the statements of cash flows was previously disclosed in operating activities for Southern Company and Southern Company Gas and in investing activities for Southern Company and Southern Power. See "Restricted Cash" herein for additional information.
In March 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in the statements of income outside of income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. The registrants adopted ASU 2017-07 effective January 1, 2018 with no material impact on their financial statements. ASU 2017-07 has been applied retrospectively for the presentation of the service cost component and the other components of net periodic benefit costs in the statements of income for Southern Company, the traditional electric operating companies, and Southern Company Gas. Since Southern Power did not participate in the qualified pension and postretirement benefit plans until December 2017, no retrospective presentation of Southern Power's net periodic benefits costs is required. The requirement to limit capitalization to the service cost component of net periodic benefit costs has been applied on a prospective basis from the date of adoption for all registrants. The presentation changes resulted in a decrease in operating income and an increase in other income for the three and six months ended June 30, 2018 and 2017 for Southern Company, the traditional electric operating companies, and Southern Company Gas.
In August 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities (ASU 2017-12). ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The registrants adopted ASU 2017-12 effective January 1, 2018 with no material impact on their financial statements. See Note (I) for disclosures required by ASU 2017-12.
On February 14, 2018, the FASB issued ASU No. 2018-02, Income Statement – Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income (ASU 2018-02) to address the application of ASC 740, Income Taxes (ASC 740) to certain provisions of the Tax Reform Legislation. ASU 2018-02 specifically addresses the ASC 740 requirement that the effect of a change in tax laws or rates on deferred tax assets and liabilities be included in income from continuing operations, even when the tax effects were initially recognized directly in OCI at the previous rate, which strands the income tax rate differential in accumulated OCI. The amendments in ASU 2018-02 allow a reclassification from accumulated OCI to retained earnings for stranded tax effects resulting from the Tax Reform Legislation. The registrants adopted ASU 2018-02 effective January 1, 2018 with no material impact on their financial statements.
Asset Retirement Obligations
See Note 1 to the financial statements of Southern Company and the traditional electric operating companies under "Asset Retirement Obligations and Other Costs of Removal" in Item 8 of the Form 10-K for additional information regarding each company's AROs and the EPA's Disposal of Coal Combustion Residuals from Electric Utilities final rule (CCR Rule).

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

As of June 30, 2018, details of the AROs, including those related to the CCR Rule, included in the condensed balance sheets of Southern Company, Alabama Power, and Mississippi Power were as follows:
 Southern Company 
Alabama
Power
 
Mississippi
Power
 (in millions)
Balance at December 31, 2017$4,824
 $1,709
 $174
Liabilities incurred1
 
 
Liabilities settled(97) (19) (15)
Accretion95
 41
 2
Cash flow revisions1,493
 1,451
 15
Reclassification to held for sale(148) 
 
Balance at June 30, 2018$6,168
 $3,182
 $176
In June 2018, Alabama Power recorded an increase of approximately $1.2 billion to its AROs related to the CCR Rule. The revised cost estimates as of June 30, 2018 are based on information from feasibility studies performed on ash ponds in use at plants operated by Alabama Power, including a plant jointly-owned by Mississippi Power. During the second quarter 2018, Alabama Power's management completed its analysis of these studies which indicated that additional closure costs, primarily related to increases in estimated ash volume, water management requirements, and design revisions, will be required to close these ash ponds under the planned closure-in-place methodology. As a result of these revised cost estimates, in June 2018, Mississippi Power recorded an increase of approximately $11 million to its AROs related to an ash pond at the plant jointly-owned with Alabama Power.
Georgia Power continues to perform engineering studies related to its plans to close the ash ponds at all of its generating plants, including one jointly owned with Gulf Power, in compliance with federal and state CCR rules. Georgia Power also continues to refine its closure strategy and cost estimates for each ash pond and is preparing permit applications as required by the State of Georgia CCR rule. While each of Georgia Power and Gulf Power believes its recorded liability for ash pond closures appropriately reflects its obligations under the current closure strategies it has elected, changes to such strategies and cost estimates would likely result in additional closure costs which would increase each of Georgia Power's and Gulf Power's ARO liability. It is not currently possible to determine the magnitude of an increase related to a change in closure strategies nor an increase related to ongoing engineering studies for the current closure strategies, and the timing of future cash outflows are indeterminable at this time. As permit applications advance, engineering studies continue, and the timing of ash pond closures develop further on a plant-by-plant basis during the second half of 2018 and in the future, Georgia Power will record any changes as necessary to its ARO liability, which could be material. Georgia Power expects to continue to periodically update these cost estimates as necessary, which could change further as additional information becomes available. Gulf Power will record any incremental AROs, which could be material, related to its share of Plant Scherer Unit 3, which is co-owned with Georgia Power, once Georgia Power further refines its cost estimate of the impact on its ARO liability.
As further analysis is performed and closure details are developed with respect to ash pond closures, the traditional electric operating companies expect to periodically update their cost estimates as necessary. Absent continued recovery of ARO costs through regulated rates, Southern Company's and the traditional electric operating companies' results of operations, cash flows, and financial condition could be materially impacted. The ultimate outcome of this matter cannot be determined at this time.
In June 2018, Alabama Power completed an updated decommissioning cost site study for Plant Farley. The estimated cost of decommissioning based on the study resulted in an increase in Southern Company's and Alabama Power's ARO liability of approximately $300 million. See "Nuclear Decommissioning" below for additional information.

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

The reclassification of a portion of the ARO liability to liabilities held for sale by Southern Company represents the AROs related to Gulf Power. See Note (J) under "Southern Company's Sale of Gulf Power" and "Assets Held for Sale" for additional information.
Nuclear Decommissioning
See Note 1 to the financial statements of Southern Company and Alabama Power under "Nuclear Decommissioning" in Item 8 of the Form 10-K for additional information.
In June 2018, Alabama Power completed an updated decommissioning cost site study for Plant Farley. The estimated costs of decommissioning based on the 2018 site study are as follows:
Decommissioning periods: 
Beginning year2037
Completion year2076
  
 (in millions)
Site study costs: 
Radiated structures$1,621
Non-radiated structures99
Total site study costs$1,720
The decommissioning cost estimates are based on prompt dismantlement and removal of the plant from service. The actual decommissioning costs may vary from the above estimates because of changes in the assumed date of decommissioning, changes in NRC requirements, or changes in the assumptions used in making these estimates.
For ratemaking purposes, Alabama Power's decommissioning costs are based on the site study. Significant assumptions used to determine these costs for ratemaking were an inflation rate of 4.5% and a trust earnings rate of 7.0%. The next site study is expected to be completed in 2023.
Amounts previously contributed to the external trust funds are currently projected to be adequate to meet the updated decommissioning obligations. Alabama Power will continue to provide site specific estimates of the decommissioning costs and related projections of funds in the external trust to the Alabama PSC and, if necessary, would seek the Alabama PSC's approval to address any changes in a manner consistent with the NRC and other applicable requirements.

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

Goodwill and Other Intangible Assets
The following table presents year-to-date changes in goodwill balances for Southern CompanyGoodwill at March 31, 2019 and Southern Company Gas:
December 31, 2018 was as follows:
 Goodwill
 Southern Company Southern Company Gas
  Gas Distribution OperationsGas Marketing ServicesTotal
 (in millions)
Balance at December 31, 2017$6,268
 $4,702
$1,265
$5,967
Impairment(a)
(42) 
(42)(42)
Sale of Pivotal Home Solutions(a)
(242) 
(242)(242)
Reclassification to held for sale(b)
(668) (668)
(668)
Balance at June 30, 2018$5,315
(c) 
$4,034
$981
$5,015
 At March 31, 2019At December 31, 2018
 (in millions)
Southern Company$5,284
$5,315
Southern Company Gas:  
Gas distribution operations$4,034
$4,034
Gas marketing services981
981
Southern Company Gas total$5,015
$5,015
(a)
On April 11, 2018, Southern Company Gas entered into a stock purchase agreement for the sale of Pivotal Home Solutions. In contemplation of the transaction, a goodwill impairment charge of $42 million was recorded in the first quarter 2018. On June 4, 2018, Southern Company Gas and Pivotal Home Solutions completed this transaction. See Note (J) under "Southern Company Gas" for additional information.
(b)
Reflects goodwill associated with Elizabethtown Gas, Elkton Gas, and Florida City Gas, which were sold subsequent to June 30, 2018. See Note (J) under "Southern Company Gas" and "Assets Held for Sale" for additional information.
(c)Total does not add due to rounding.
Goodwill is not amortized but is subject to an annual impairment test during the fourth quarter of each year or more frequently if impairment indicators arise.

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(UNAUDITED)

Other intangible assets were as follows:
At June 30, 2018 At December 31, 2017At March 31, 2019 At December 31, 2018
Gross Carrying AmountAccumulated Amortization
Other
Intangible Assets, Net
 Gross Carrying AmountAccumulated AmortizationOther
Intangible Assets, Net
Gross Carrying AmountAccumulated Amortization
Other
Intangible Assets, Net
 Gross Carrying AmountAccumulated AmortizationOther
Intangible Assets, Net
(in millions) (in millions)(in millions) (in millions)
Southern Company      
Other intangible assets subject to amortization:      
Customer relationships(*)
$223
$(79)$144
 $288
$(83)$205
Trade names(*)
70
(17)53
 159
(17)142
Customer relationships$211
$(100)$111
 $223
$(94)$129
Trade names70
(22)48
 70
(21)49
Storage and transportation contracts64
(44)20
 64
(34)30
64
(56)8
 64
(54)10
PPA fair value adjustments456
(60)396
 456
(47)409
405
(67)338
 405
(61)344
Other19
(5)14
 17
(5)12
11
(6)5
 11
(5)6
Total other intangible assets subject to amortization$832
$(205)$627

$984
$(186)$798
$761
$(251)$510

$773
$(235)$538
Other intangible assets not subject to amortization:      
Federal Communications Commission licenses75

75
 75

75
75

75
 75

75
Total other intangible assets$907
$(205)$702
 $1,059
$(186)$873
$836
$(251)$585
 $848
$(235)$613
      
Southern Power      
Other intangible assets subject to amortization:      
PPA fair value adjustments$456
$(60)$396
 $456
$(47)$409
$405
$(67)$338
 $405
$(61)$344
      
Southern Company Gas      
Other intangible assets subject to amortization:      
Gas marketing services(*)
   
Gas marketing services   
Customer relationships$156
$(71)$85
 $221
$(77)$144
$156
$(89)$67
 $156
$(84)$72
Trade names26
(6)20
 115
(9)106
26
(8)18
 26
(7)19
Wholesale gas services      
Storage and transportation contracts64
(44)20
 64
(34)30
64
(56)8
 64
(54)10
Total other intangible assets subject to amortization$246
$(121)$125
 $400
$(120)$280
$246
$(153)$93
 $246
$(145)$101
(*)
Balances as of June 30, 2018 reflect Southern Company Gas' sale of Pivotal Home Solutions. See Note (J) under "Southern Company GasSale of Pivotal Home Solutions" for additional information.

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(UNAUDITED)

Amortization associated with other intangible assets was as follows:
Three Months EndedSix Months EndedThree Months Ended
June 30, 2018March 31, 2019
(in millions)(in millions)
Southern Company$23
$50
$17
Southern Power(a)$6
$13
$6
Southern Company Gas$14
$31
 
Gas marketing services(b)
$6
Wholesale gas services(a)
2
Southern Company Gas total$8
(a)Recorded as a reduction to operating revenues.
(b)Included in depreciation and amortization.
Restricted Cash
The registrants adopted ASU 2016-18 as of January 1, 2018. See "Recently Adopted Accounting StandardsOther" herein for additional information.
At December 31, 2017, Southern2018, Georgia Power had restricted cash primarily related to certain acquisitions and construction projects.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, 2018March 31, 2019 and December 31, 2017,2018, 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, 2018March 31, 2019 and/or December 31, 2017:2018:
Southern Company Southern Company GasSouthern Company Southern Company Gas
(in millions)(in millions)
At June 30, 2018   
At March 31, 2019   
Cash and cash equivalents$1,980
 $69
$1,361
 $57
Cash and cash equivalents classified as assets held for sale31
 
Restricted cash:      
Other accounts and notes receivable6
 6
4
 4
Total cash, cash equivalents, and restricted cash$2,017
 $75
$1,364
(*) 
$61
(*)Total does not add due to rounding.
Southern Company
Southern
Power
Southern Company GasSouthern Company
Georgia
Power
Southern Company Gas
(in millions)(in millions)
At December 31, 2017 
At December 31, 2018 
Cash and cash equivalents$2,130
$129
$73
$1,396
$4
$64
Cash and cash equivalents held for sale9


Restricted cash:  
Restricted cash
108

Other accounts and notes receivable5

5
114

6
Deferred charges and other assets12
11

Total cash, cash equivalents, and restricted cash$2,147
$140
$78
$1,519
$112
$70

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(UNAUDITED)

Natural Gas for Sale
Southern Company Gas' natural gas distribution utilities,Gas, with the exception of Nicor Gas, carrycarries 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 had no material adjustment in any period presented.
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' inventory decrement at March 31, 2019 is expected to be restored prior to year end.
(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 March 31, 2019 and December 31, 2018 were as follows:
Regulatory ClauseBalance Sheet Line ItemMarch 31,
2019
December 31,
2018
  (in millions)
Alabama Power   
Rate CNP ComplianceDeferred under recovered regulatory clause revenues$
$42
 Customer accounts receivable25

Rate CNP PPADeferred under recovered regulatory clause revenues21
25
Retail Energy Cost Recovery(*)
Deferred under recovered regulatory clause revenues
109
 Other regulatory liabilities, deferred2

Natural Disaster ReserveOther regulatory liabilities, deferred22
20
Georgia Power   
Fuel Cost RecoveryReceivables – under recovered fuel clause revenues$73
$115
Mississippi Power   
Fuel Cost RecoveryOver recovered retail fuel costs$10
$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
In connection with management's decision to retire Plant Gorgas, in February 2019, Alabama Power reclassified approximately $1.3 billion for Plant Gorgas Unit 10 from plant in service, net of depreciation to other utility plant, net and continued to depreciate the asset according to the original depreciation rates. On April 15, 2019, Alabama Power retired Plant Gorgas Units 8, 9, and 10 and reclassified approximately $740 million of the remaining net investment costs of the units to a regulatory asset to be recovered over the units' remaining useful lives as established prior to the decision to retire. Additionally, approximately $700 million of net capitalized asset

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(UNAUDITED)

costretirement costs will be reclassified to a regulatory asset and recovered in accordance with accounting guidance provided by the Alabama PSC. See Note 2 to the financial statements under "Alabama Power – Environmental Accounting Order" and Note 6 in Item 8 of the inventory layers liquidated. Southern Company Gas' inventory decrementForm 10-K for additional information.
Georgia Power
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 June 30, 2018 is expectedany time for their convenience, provided that the Vogtle Owners will be required to be restoredpay amounts related to work performed prior to year end. The costthe termination (including the applicable portion of natural gas, including inventory costs, is recovered from customers under a purchased gas recovery mechanism adjusted for differences between actualthe base fee), certain termination-related costs, and, amounts billed; therefore, LIFO liquidations have no impact on Southern Company's or Southern Company Gas' net income.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.
Natural gas inventories for Southern Company Gas' non-utility businesses are carried at the lower
147

Table of weighted average cost or current market price, with cost determined on a WACOG basis. For any declines in market prices below the WACOG considered to be other than temporary, an adjustment is recorded to reduce the value of natural gas inventories to market value. Southern Company Gas had no material LOCOM adjustment in any period presented.Contents
Hypothetical Liquidation at Book Value
Southern Power has consolidated renewable generation projects that are partially funded by a third-party tax equity investor. The related contractual provisions represent profit-sharing arrangements because the allocations of cash distributionsNOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

Cost and tax benefits are not based on fixed ownership percentages. Therefore, the noncontrolling interest is accounted for under a balance sheet approach utilizing the hypothetical liquidation at book value (HLBV) method. The HLBV method calculates each partner'sSchedule
Georgia Power's approximate proportionate share of income based on the change in net equityremaining estimated capital cost to complete Plant Vogtle Units 3 and 4 by the partner can legally claim in a hypothetical liquidation at the endexpected in-service dates of the period compared to the beginning of the period.November 2021 and November 2022, respectively, is as follows:
 (in billions)
Base project capital cost forecast(a)(b)
$8.0
Construction contingency estimate0.4
Total project capital cost forecast(a)(b)
8.4
Net investment as of March 31, 2019(b)
(4.9)
Remaining estimate to complete(a)
$3.5
(B)(a)CONTINGENCIES AND REGULATORY MATTERSExcludes financing costs expected to be capitalized through AFUDC of approximately $325 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 $1.9 billion had been incurred through March 31, 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 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.
As construction continues, 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), any of which may require additional labor and/or materials; or other issues could arise and change the projected schedule and estimated cost. Monthly construction production targets established as part of a strategy to maintain and build margin to the approved in-service dates will continue to increase significantly throughout 2019. To meet these increasing monthly targets, existing craft construction productivity must improve and additional craft laborers 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 resolution of ITAAC and the related approvals by the NRC, may arise, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs.
The ultimate outcome of these matters cannot be determined at this time. However, any extension of the 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.

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(UNAUDITED)

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 March 31, 2019, Georgia Power had recovered approximately $1.9 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 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

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(UNAUDITED)

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 $75 million in 2019 and an aggregate of approximately $635 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 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). In addition, the staff of the Georgia PSC requested, and Georgia Power agreed, to report the results of the cost and schedule validation process to the Georgia PSC (which is expected to occur by May 1, 2019) and to file its twentieth VCM report concurrently with the twenty-first VCM report by August 31, 2019.

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(UNAUDITED)

The ultimate outcome of these matters cannot be determined at this time.
DOE Financing
At March 31, 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 March 28, 2019, Mississippi Power filed a request with the FERC 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. The MRA settlement agreement provides that base rates will decrease $3.7 million annually, effective January 1, 2019. Mississippi Power expects the matter to be resolved in the second quarter 2019. The ultimate outcome of this matter cannot be determined at this time.
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 first quarter 2019, Mississippi Power recorded pre-tax charges to income of $2 million ($1 million after tax), 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 salvage, net of dismantlement costs), 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 $11 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

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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 within the statutory time limit of 11 months from the filing of the rate case, after which rate adjustments will be effective. 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 $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 third quarter 2019. The ultimate outcome of this matter cannot be determined at this time.

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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 March 25, 2019, the Alabama Municipal Electric Authority and Cooperative Energy and SCS and the traditional electric operating companies filed a formal settlement agreement with the FERC agreeing to a 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 ultimate outcome of this matter cannot be determined at this time; however, if approved by the FERC as filed, the OATT settlement would 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 of the registrants in Item 8 of the Form 10-K for information relating to various lawsuits and other contingencies, and regulatory matters.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 natural resources. Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental laws and regulations, has occurred throughout the U.S. This litigation has included claims for damages alleged to have been caused by CO2 and other emissions, CCR, and alleged exposure to hazardous materials, and/or requests for injunctive relief in connection with such matters.
The ultimate outcome of such pending or potential litigation against each registrant and any subsidiaries cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on such registrant's financial statements.
Southern Company
In January 2017, a putative securities class action complaint was filed against Southern Company, certain of its officers, and certain former Mississippi Power officers in the U.S. District Court for the Northern District of Georgia Atlanta Division, by Monroe County Employees' Retirement System on behalf of all persons who purchased shares of Southern Company's common stock between April 25, 2012 and October 29, 2013. The complaint alleges that Southern Company, certain of its officers, and certain former Mississippi Power officers made materially false and misleading statements regarding the Kemper County energy facility in violation of certain provisions under the Securities Exchange Act of 1934, as amended. The complaint seeks, among other things, compensatory damages and litigation costs and attorneys' fees. In June 2017, the plaintiffs filed an amended complaint that provided additional detail about their claims, increased the purported class period by one day, and added certain other former Mississippi Power officers as defendants. In JulyAlso in 2017, the defendants filed a motion to dismiss the plaintiffs' amended complaint with prejudice, to which the plaintiffs filed an opposition in September 2017. Onopposition. In March 29, 2018, the U.S. District Court for the Northern District of Georgia, Atlanta Division,court issued an

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order granting, in part, the defendants' motion to dismiss. The court dismissed certain claims against certain officers of Southern Company and Mississippi Power and dismissed the allegations related to a number of the statements that plaintiffs challenged as being false or misleading. OnIn April 26, 2018, the defendants filed a motion for reconsideration of the court's order, seeking dismissal of the remaining claims in the lawsuit. In August 2018, the court denied the motion for reconsideration and denied a motion to certify the issue for interlocutory appeal.

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In February 2017, Jean Vineyard and Judy Mesirov each filed a shareholder derivative lawsuit and, in May 2017, Judy Mesirov filed a shareholder derivative lawsuit, each in the U.S. District Court for the Northern District of Georgia. Each of these lawsuits names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. In August 2017, these two shareholder derivative lawsuits were consolidated in the U.S. District Court for the Northern District of Georgia. The complaints allege that the defendants caused Southern Company to make false or misleading statements regarding the Kemper County energy facility cost and schedule. Further, the complaints allege that the defendants were unjustly enriched and caused the waste of corporate assets and also allege that the individual defendants violated their fiduciary duties. Each plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and, on each plaintiff's own behalf, attorneys' fees and costs in bringing the lawsuit. Each plaintiff also seeks certain changes to Southern Company's corporate governance and internal processes. OnIn April 25, 2018, the court entered an order staying this lawsuit until 30 days after the resolution of any dispositive motions or any settlement, whichever is earlier, in the putative securities class action.
In May 2017, Helen E. Piper Survivor's Trust filed a shareholder derivative lawsuit in the Superior Court of Gwinnett County, State of Georgia that names as defendants Southern Company, certain of its directors, certain of its officers, and certain former Mississippi Power officers. The complaint alleges that the individual defendants, among other things, breached their fiduciary duties in connection with schedule delays and cost overruns associated with the construction of the Kemper County energy facility. The complaint further alleges that the individual defendants authorized or failed to correct false and misleading statements regarding the Kemper County energy facility schedule and cost and failed to implement necessary internal controls to prevent harm to Southern Company. The plaintiff seeks to recover, on behalf of Southern Company, unspecified actual damages and disgorgement of profits and, on its behalf, attorneys' fees and costs in bringing the lawsuit. The plaintiff also seeks certain unspecified changes to Southern Company's corporate governance and internal processes. TheIn 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.
Southern Company believes these legal challenges have no merit; however, an adverse outcome in any of these proceedings could have an impact on Southern Company's results of operations, financial condition, and liquidity. Southern Company will vigorously defend itself in these matters, the ultimate outcome of which cannot be determined at this time.
Alabama Power
On March 2, 2018, the Alabama Department of Environmental Management (ADEM) issued proposed administrative orders assessing a penalty of $1.25 million to Alabama Power for unpermitted discharge of fluids and/or pollutants to groundwater at five electric generating plants. The proposed orders also require the submission to the ADEM of a plan with a schedule for implementation of a comprehensive groundwater investigation, including an assessment of corrective measures, a report evaluating any deficiencies at the facilities that may have led to the unpermitted discharges, and quarterly progress reports. Alabama Power is awaiting finalization of the orders. The ultimate outcome of this matterthese 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 (all of which(which fees are remittedpaid to municipalities) exceeded the amounts allowed in orders of the Georgia PSC and alleging certain state tort law claims. In 2016, the Georgia Court of Appeals reversed the trial court's previous dismissal of the case and remanded the case to the trial court. Georgia Power filed a petition for writ of certiorari with the Georgia Supreme Court, which was granted in August 2017. OnIn June 18, 2018, the Georgia Supreme Court affirmed the judgment of the

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
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Georgia Court of Appeals and remanded the case has been remanded 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 and the plaintiffs also have filed notices 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 and intends to vigorously defend itself in this matter.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 will ultimately be certified; the scope of such a class, if certified; and whether any losses would be subject to recovery from any municipalities. The ultimate outcome of this matter cannot be determined at this time.

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Mississippi Power
In 2016, a complaint against Mississippi Power was filed in Harrison County Circuit Court (Circuit Court) by Biloxi Freezing & Processing Inc., Gulfside Casino Partnership, and John Carlton Dean, which was amended and refiled to include, among other things, Southern Company as a defendant. The individual plaintiff alleged that Mississippi Power and Southern Company violated the Mississippi Unfair Trade Practices Act. All plaintiffs alleged that Mississippi Power and Southern Company concealed, falsely represented, and failed to fully disclose important facts concerning the cost and schedule of the Kemper County energy facility and that these alleged breaches unjustly enriched Mississippi Power and Southern Company. The plaintiffs sought unspecified actual damages and punitive damages; asked the Circuit Court to appoint a receiver to oversee, operate, manage, and otherwise control all affairs relating to the Kemper County energy facility; asked the Circuit Court to revoke any licenses or certificates authorizing Mississippi Power or Southern Company to engage in any business related to the Kemper County energy facility in Mississippi; and sought attorney's fees, costs, and interest. The plaintiffs also sought an injunction to prevent any Kemper County energy facility costs from being charged to customers through electric rates. In June 2017, the Circuit Court ruled in favor of motions by Southern Company and Mississippi Power and dismissed the case. In July 2017, the plaintiffs filed notice of an appeal. On July 13, 2018, Mississippi Power and Southern Company reached a settlement agreement with the plaintiffs and the plaintiffs' appeal was dismissed with prejudice. The settlement had no material impact on Southern Company's or Mississippi Power's financial statements.
On May 18, 2018, Southern Company and Mississippi Power received a notice of dispute and arbitration demand filed by Martin Product Sales, LLC (Martin) based on two agreements, both related to Kemper IGCC byproducts for which Mississippi Power provided termination notices in September 2017. Martin alleges breach of contract, breach of good faith and fair dealing, fraud and misrepresentation, and civil conspiracy and makes a claim for damages in the amount of approximately $143 million, as well as additional unspecified damages, attorney's fees, costs, and interest. In the first quarter 2019, Mississippi Power and Southern Company filed motions to dismiss. Southern Company and Mississippi Power believe this legal challenge has no merit; however, an adverse outcome in this proceeding could have a material impact on Southern Company's and Mississippi Power's results of operations, financial condition, and liquidity. Southern Company and Mississippi Power will vigorously defend themselves in this matter, theThe ultimate outcome of whichthis matter cannot be determined at this time.
On MayIn 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 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, 2018,2019. 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 this legal challenge has no merit; however, an adverse outcome in this proceeding could have a material impact on Mississippi Power's claim for lost revenue resulting from the Deepwater Horizon oil spill in the Gulfresults of Mexico in 2010 was settled.operations, financial condition, and liquidity. The settlement proceedsultimate outcome of $18 million, net of expenses and income tax, are included in Southern Company's and Mississippi Power's earnings for the second quarter 2018.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 November 2016, certain solar panels were damaged during installation by the construction contractor, McCarthy Building Companies, Inc. (McCarthy), and certain solar panels were damaged by a hail event that also occurred during construction. In Mayconnection 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 (State Court lawsuit) against XL Insurance America, Inc. (XL) and North American Elite Insurance Company (North American Elite) seeking recovery from an insurance policy for damages resulting from the hail stormevent and McCarthy's installation practices. OnIn June 1, 2018, the court in the State Court lawsuit granted Roserock's motion for partial summary judgment, finding that the insurers were in breach of contract and in violation of the Texas Insurance Code for failing to pay any monies owed for the hail claim. Separate lawsuits were filed between Roserock is working to distinguish its damages between those attributableand 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 hail event versus damages attributablestate and federal lawsuits executed a settlement agreement and mutual release that resolves both lawsuits. Under the agreement, the lawsuits will be dismissed and McCarthy will release its lien following payments of all amounts (which are expected to installation.occur in May 2019). Roserock will pay $26 million to McCarthy that was withheld and included in the original construction costs and will receive funds that will cover all related legal costs and the replacement costs of certain solar panels. In addition, during the first quarter 2019, Roserock received a partial payment of approximately $5 million in insurance proceeds toward the hail event. Any additional funds received in excess of the initial replacement costs are expected to be recognized as a gain when received by Roserock in the State Court lawsuit, lawsuits were filedsecond quarter 2019, but are not expected to have a material impact on Southern Power's net income.

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between Roserock and McCarthy, as well as other parties, and that litigation has been consolidated in the U.S. District Court for the Western District of Texas. Southern Power intends to vigorously pursue and defend these matters, the ultimate outcome of which cannot be determined at this time.
Southern Company Gas
Nicor Energy Services Company, doing business as Pivotal Home Solutions, formerly a wholly-owned subsidiary of Southern Company Gas, was a defendant in a putative class action initially filed in 2017 in the state court in Indiana. The plaintiffs purported to represent a class of the customers who purchased products from Nicor Energy Services Company and alleged that the marketing, sale, and billing of the products violated the Indiana Consumer Fraud and Deceptive Business Practices Act, constituting common law fraud and resulting in unjust enrichment of these entities. In 2018, Nicor Energy Services Company was named in a second class action filed in the state court of Ohio asserting nearly identical allegations and legal claims. The plaintiffs sought, on behalf of the classes they purported to represent, actual and punitive damages, interest costs, attorney fees, and injunctive relief. To facilitate the sale of Pivotal Home Solutions, Southern Company Gas retained most of the financial responsibility for these lawsuits following the completion of the sale. On June 12, 2018, the parties settled these claims and Southern Company Gas recorded an $11 million charge, which is reflected in other operations and maintenance expenses on the statements of income.
Environmental Matters
Environmental Remediation
The Southern Company system must comply with environmental laws and regulations governing the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, the Southern Company system could incur substantial costs to clean up affected sites. The traditional electric operating companies and the natural gas distribution utilities in Illinois New Jersey,and Georgia and Florida have alleach received authority from their respective state PSCs or other applicable state regulatory agencies to recover approved environmental compliance costs through regulatory mechanisms. These regulatory mechanisms are adjusted annually or as necessary within limits approved by the state PSCs or other applicable state regulatory agencies.
Georgia Power's environmental remediation liability was $25$18 million and $22$23 million as of June 30, 2018March 31, 2019 and December 31, 2017,2018, 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.
Gulf Power's environmental remediation liability includes estimated costs of environmental remediation projects of approximately $48 million and $52 million as of June 30, 2018 and December 31, 2017, respectively. These estimated costs primarily relate to site closure criteria by the Florida Department of Environmental Protection (FDEP) for potential impacts to soil and groundwater from herbicide applications at Gulf Power's substations. The schedule for completion of the remediation projects is subject to FDEP approval.
At June 30, 2018, Southern Company Gas' environmental remediation liability was $305$289 million and $294 million as of March 31, 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, with an additional $77 million liability related to Elizabethtown Gas classified as held for sale. At December 31, 2017, Southern Company Gas' total environmental remediation liability was $388 million, of which $85 million related to Elizabethtown Gas.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. See Note (J) under "Southern Company Gas" and "Assets Held for Sale" for additional information.
The ultimate outcome of these matters cannot be determined at this time; however, as a result of the regulatory treatment for environmental remediation expenses described above, the final disposition of these matters is not

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
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expected to have a material impact on the financial statements of Southern Company, Georgia Power, Gulf Power, or Southern Company Gas.
FERC
Other Matters
Market-Based Rate AuthorityMississippi Power
See Note 3In 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 financial statementsrestructuring, own 100% of Southern Company, the traditional electric operating companies, and Southerna generating unit. On January 15, 2019, Gulf Power under "FERC Matters" in Item 8provided notice to Mississippi Power that Gulf Power will retire its share of the Form 10-Kgenerating capacity of Plant Daniel on January 15, 2024. Mississippi Power has the option to purchase Gulf Power's ownership interest for additional information regarding proceedings related$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 traditional electric operating companies'potential operational and Southerneconomic effects of Gulf Power's 2014 and 2017 triennial market power analyses.
On May 4, 2018, the FERC issued an order terminating both proceedings, finding that the traditional electric operating companies and Southern Power satisfy the FERC's standards for market-based rates. On May 9, 2018, the traditional electric operating companies and Southern Power made the compliance filing required by the order. These proceedings are essentially concluded.
Open Access Transmission Tariff
On May 10, 2018, the Alabama Municipal Electric Authority and Cooperative Energy filed with the FERC a complaint against SCS and the traditional electric operating companies claiming that the current 11.25% base ROE used in calculating the annual transmission revenue requirements of the traditional electric operating companies' open access transmission tariff is unjust and unreasonable as measured by the applicable FERC standards. The complaint requests that the base ROE be set no higher than 8.65% and that the FERC order refunds for the difference in revenue requirements that results from applying a just and reasonable ROE established in this proceeding upon determining the current ROE is unjust and unreasonable. On June 18, 2018, SCS and the traditional electric operating companies filed their response challenging the adequacy of the showing presented by the complainants and offering support for the current ROE.notice. The ultimate outcome of this matterthese 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.
Cooperative Energy Power Supply Agreement
See Note 3 to the financial statements of Mississippi Power(K) under "FERC Matters – Cooperative Energy Power Supply Agreement" in Item 8 of the Form 10-K for additional information regarding Cooperative Energy's network integration transmission service agreement (NITSA) with SCS.
On March 23, 2018, the FERC accepted the amendment to the NITSA between Cooperative Energy and SCS, effective April 1, 2018.

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Regulatory Matters
Alabama Power
"See Note 3 to the financial statements of Southern Company and Alabama Power under "Regulatory Matters Alabama Power" and "Retail Regulatory Matters," respectively, in Item 8 of the Form 10-K for additional information regarding Alabama Power's recovery of retail costs through various regulatory clauses and accounting orders. The balance of each regulatory clause recovery on the balance sheet follows:
Regulatory ClauseBalance Sheet Line ItemJune 30,
2018
December 31,
2017
  (in millions)
Rate CNP ComplianceDeferred under recovered regulatory clause revenues$30
$17
Rate CNP PPADeferred under recovered regulatory clause revenues11
12
Retail Energy Cost RecoveryDeferred under recovered regulatory clause revenues80
25
 Under recovered regulatory clause revenues28

Natural Disaster ReserveOther regulatory liabilities, deferred30
38
On May 1, 2018, the Alabama PSC approved modifications to Rate RSE and other commitments designed to position Alabama Power to address the growing pressure on its credit quality resulting from the Tax Reform Legislation, without increasing retail rates under Rate RSE in the near term. Alabama Power plans to reduce growth in total debt by increasing equity, with corresponding reductions in debt issuances, thereby de-leveraging its capital structure. Alabama Power's goal is to achieve an equity ratio of approximately 55% by the end of 2025. At June 30, 2018, Alabama Power's equity ratio was approximately 46.6%.
Rate RSE
The approved modifications to Rate RSE became effective June 2018 and are applicable for January 2019 billings and thereafter. The modifications include reducing the top of the allowed weighted common equity return (WCER) range from 6.21% to 6.15% and modifications to the refund mechanism applicable to prior year actual results. The modifications to the refund mechanism allow Alabama Power to retain a portion of the revenue that causes the actual WCER for a given year to exceed the allowed range.
Generally, if Alabama Power's actual WCER range is between 6.15% and 7.65%, customers will receive 25% of the amount between 6.15% and 6.65%, 40% of the amount between 6.65% and 7.15%, and 75% of the amount between 7.15% and 7.65%. Customers will receive all amounts in excess of an actual WCER of 7.65%.
In conjunction with these modifications to Rate RSE, on May 8, 2018, Alabama Power consented to a moratorium on any upward adjustments under Rate RSE for 2019 and 2020. Additionally, Alabama Power will return $50 million to customers through bill credits in 2019.
In accordance with an established retail tariff that provides for an interim adjustment to customer billings to recognize the impact of a change in the statutory income tax rate, Alabama Power is returning approximately $257 million to retail customers through bill credits in the second half of 2018 as a result of the change in the federal income tax rate under the Tax Reform Legislation.
Rate ECR
On May 1, 2018, the Alabama PSC approved an increase to Rate ECR from 2.015 cents per KWH to 2.353 cents per KWH effective July 2018 which is expected to result in additional collections of approximately $100 million through December 31, 2018. The approved increase in the Rate ECR factor will have no significant effect on

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Alabama Power's net income, but will increase operating cash flows related to fuel cost recovery in 2018. The rate will return to 5.910 cents per KWH in 2019, absent a further order from the Alabama PSC.
Accounting Order
On May 1, 2018, the Alabama PSC approved an accounting order that authorizes Alabama Power to defer the benefits of federal excess deferred income taxes associated with the Tax Reform Legislation for the year ending December 31, 2018 as a regulatory liability and to use up to $30 million of such deferrals to offset under recovered amounts under Rate ECR. Any remaining amounts will be used for the benefit of customers as determined by the Alabama PSC. As of June 30, 2018, Alabama Power had applied approximately $30 million of such deferrals to offset the under recovered balance under Rate ECR and expects the total deferrals for the year ending December 31, 2018 to be approximately $50 million. See Note 5 to the financial statements of Southern Company and Alabama Power under "Federal Tax Reform Legislation" and of Alabama Power under "Current and Deferred Income Taxes" in Item 8 of the Form 10-K for additional information.
Plant Greene County
Alabama Power jointly owns Plant Greene County with an affiliate, Mississippi Power. See Note 4 to the financial statements of Alabama Power in Item 8 of the Form 10-K for additional information regarding the joint ownership agreement. On August 6, 2018, Mississippi Power filed its proposed Reserve Margin Plan (RMP) with the Mississippi PSC, which proposes a 4-year acceleration of the retirement of Plant Greene County Units 1 and 2 to the third quarter 2021 and the third quarter 2022, respectively. Mississippi Power's proposed Plant Greene County unit retirements would require the completion of proposed transmission and system reliability improvements, as well as agreement by Alabama Power. Alabama Power will monitor Mississippi Power's proposed RMP and associated regulatory process as well as the proposed transmission and system reliability improvements. Alabama Power will review all the facts and circumstances and will evaluate all its alternatives prior to reaching a final determination on the ongoing operations of Plant Greene County. The ultimate outcome of this matter cannot be determined at this time.
Georgia Power
Georgia Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Georgia PSC. Georgia Power currently recovers its costs from the regulated retail business through the 2013 ARP, which includes traditional base tariff rates, Demand-Side Management tariffs, Environmental Compliance Cost Recovery tariffs, and Municipal Franchise Fee tariffs. In addition, financing costs related to certified construction costs of Plant Vogtle Units 3 and 4 are being collected through the NCCR tariff and fuel costs are collected through a separate fuel cost recovery tariff. See "Nuclear Construction" herein and Note 3 to the financial statements of Southern Company under "Nuclear Construction" and Georgia Power under "Retail Regulatory Matters – Nuclear Construction" in Item 8 of the Form 10-K for additional information regarding the NCCR tariff. Also see "Fuel Cost Recovery" herein and Note 3 to the financial statements of Southern Company under "Regulatory Matters – Georgia Power – Fuel Cost Recovery" and Georgia Power under "Retail Regulatory Matters – Fuel Cost Recovery" in Item 8 of the Form 10-K for additional information regarding fuel cost recovery.
Rate Plans
See Note 3 to the financial statements of Southern Company and Georgia Power under "Regulatory Matters – Georgia Power – Rate Plans" and "Retail Regulatory Matters – Rate Plans," respectively, in Item 8 of the Form 10-K for additional information regarding Georgia Power's 2013 ARP and the Georgia PSC's 2018 order related to the Tax Reform Legislation.
On April 3, 2018, the Georgia PSC approved a settlement agreement between Georgia Power and the staff of the Georgia PSC regarding the retail rate impact of the Tax Reform Legislation (Georgia Power Tax Reform Settlement Agreement). Pursuant to the Georgia Power Tax Reform Settlement Agreement, to reflect the federal income tax rate reduction impact of the Tax Reform Legislation, Georgia Power will refund to customers a total of $330 million through bill credits of $131 million in October 2018, $96 million in June 2019, and $103 million in February 2020.

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In addition, Georgia Power is deferring as a regulatory liability (i) the revenue equivalent of the tax expense reduction resulting from legislation lowering the Georgia state income tax rate from 6.00% to 5.75% in 2019 and (ii) the entire benefit of approximately $700 million in federal and state excess accumulated deferred income taxes. The amortization of these regulatory liabilities is expected to be addressed in Georgia Power's next base rate case, which is scheduled to be filed by July 1, 2019. If there is not a base rate case in 2019, customers will receive $185 million in annual bill credits beginning in 2020, with any additional federal and state income tax savings deferred as a regulatory liability, until Georgia Power's next base rate case.
To address the negative cash flow and credit metric impacts of the Tax Reform Legislation, the Georgia PSC also approved an increase in Georgia Power's retail equity ratio to the lower of (i) Georgia Power's actual common equity weight in its capital structure or (ii) 55%, until Georgia Power's next base rate case. Benefits from reduced federal income tax rates in excess of the amounts refunded to customers will be retained by Georgia Power to cover the carrying costs of the incremental equity in 2018 and 2019.
Fuel Cost Recovery
As of June 30, 2018 and December 31, 2017, Georgia Power's under recovered fuel balance totaled $159 million and $165 million, respectively, and is included as under recovered fuel clause revenues on Southern Company's and Georgia Power's condensed balance sheets. The Georgia PSC will review Georgia Power's cumulative over or under recovered fuel balance no later than September 1, 2018 and evaluate the need to file a fuel case. Georgia Power continues to be allowed to adjust its fuel cost recovery rates under an interim fuel rider prior to the next fuel case if the under or over recovered fuel balance exceeds $200 million.
Fuel cost recovery revenues are adjusted for differences in actual recoverable fuel costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will not have a significant effect on Southern Company's or Georgia Power's revenues or net income, but will affect cash flow.
Gulf Power
See Note 3 to the financial statementssale of Gulf Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information regarding Gulf Power's rates and charges for service to retail customers.
Retail Base Rate Case
See Note 3 to the financial statements of Southern Company and Gulf Power under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" and "Retail Regulatory Matters – Retail Base Rate Cases," respectively, in Item 8 of the Form 10-K for additional information.
As a continuation of a settlement agreement approved by the Florida PSC in April 2017 (2017 Gulf Power Rate Case Settlement Agreement), on March 26, 2018, the Florida PSC approved a stipulation and settlement agreement among Gulf Power and three intervenors addressing the retail revenue requirement effects of the Tax Reform Legislation (Gulf Power Tax Reform Settlement Agreement).
The Gulf Power Tax Reform Settlement Agreement results in annual reductions to Gulf Power's revenues of $18.2 million from base rates and $15.6 million from environmental cost recovery rates, implemented April 1, 2018, and also provides for a one-time refund of $69.4 million for the retail portion of unprotected (not subject to normalization) deferred tax liabilities through a reduced fuel cost recovery rate over the remainder of 2018. Through June 30, 2018, approximately $28 million of this refund has been reflected in customer bills. As a result of the Gulf Power Tax Reform Settlement Agreement, the Florida PSC also approved an increase in Gulf Power's maximum equity ratio from 52.5% to 53.5% for all retail regulatory purposes.
As part of the Gulf Power Tax Reform Settlement Agreement, a limited scope proceeding to address protected deferred tax liabilities consistent with IRS normalization principles was initiated on April 30, 2018. Pending resolution of this proceeding, Gulf Power is deferring the related amounts for 2018 as a regulatory liability. Through June 30, 2018, amounts deferred totaled $5 million. Unless otherwise agreed to by the parties to the Gulf Power Tax Reform Settlement Agreement, amounts recorded in this regulatory liability will be refunded to retail customers in

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

2019 through Gulf Power's fuel cost recovery rates. The ultimate outcome of this matter cannot be determined at this time.
Cost Recovery Clauses
See Note 3 to the financial statements of Gulf Power under "Retail Regulatory Matters – Cost Recovery Clauses" in Item 8 of the Form 10-K for additional information regarding Gulf Power's recovery of retail costs through various regulatory clauses and accounting orders, as approved by the Florida PSC. Regulatory clause recovery balances included in the balance sheets are as follows:
Regulatory ClauseBalance Sheet Line ItemJune 30,
2018
December 31,
2017
  (in millions)
Fuel Cost RecoveryUnder recovered regulatory clause revenues$
$22
Fuel Cost RecoveryOther regulatory liabilities, current5

Purchased Power Capacity RecoveryUnder recovered regulatory clause revenues2
2
Environmental Cost Recovery(*)
Under recovered regulatory clause revenues1
2
Energy Conservation Cost RecoveryOther regulatory liabilities, current1

(*)At June 30, 2018 and December 31, 2017, the under recovered balance included in the balance sheets represents the current portion of the regulatory assets associated with projected environmental expenditures of approximately $11 million and $13 million, respectively, partially offset by the over recovered environmental cost recovery balance of approximately $10 million and $11 million, respectively.
Mississippi Power
See Note 3 to the financial statements of Mississippi Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information.
On May 8, 2018, the Mississippi PSC issued an order to begin an operations review of Mississippi Power in August 2018 with the final report expected by February 28, 2019. Mississippi Power expects that the review will include, but not be limited to, a comparative analysis of its costs, its cost recovery framework, and ways in which it may streamline management operations for the reasonable benefit of ratepayers. The ultimate outcome of this matter cannot be determined at this time.
Performance Evaluation Plan
In each of 2014, 2015, 2016, and 2017, Mississippi Power submitted its annual PEP lookback filing for the prior year, which for 2013 and 2014 each indicated no surcharge or refund and for each of 2015 and 2016 indicated a $5 million surcharge. Additionally, in July 2016, in November 2016, and on November 15, 2017, Mississippi Power submitted its annual projected PEP filings for 2016, 2017, and 2018, respectively, which for 2016 and 2017 indicated no change in rates and for 2018 indicated a rate increase of 4%, or $38 million in annual revenues. The Mississippi PSC suspended each of these filings to allow more time for review.
On February 7, 2018, Mississippi Power submitted its revised 2018 projected PEP filing to the Mississippi PSC, which reflected the impacts of the Tax Reform Legislation, requesting an increase in annual retail revenues of $26 million based on a performance adjusted ROE of 9.33% and an increased equity ratio of 55%.
On March 22, 2018, Mississippi Power submitted its annual PEP lookback filing for 2017, which reflected no surcharge or refund.
On July 27, 2018, Mississippi Power and the Mississippi Public Utilities Staff (MPUS) entered into a settlement agreement with respect to the 2018 PEP filing and all unresolved PEP filings for prior years (PEP Settlement

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
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Agreement), which was approved by the Mississippi PSC on August 7, 2018. Rates under the PEP Settlement Agreement will take effect for the first billing cycle of September 2018.
The PEP Settlement Agreement provides for an increase of approximately $21.6 million in annual base retail revenues, which excludes approximately $5.5 million requested for certain compensation costs contested by the MPUS. Under the PEP Settlement Agreement, Mississippi Power expects to defer these costs for 2018 and 2019 as a regulatory asset. The Mississippi PSC is currently expected to rule on the appropriate treatment for such costs in connection with Mississippi Power's next base rate case, which is scheduled to be filed in the fourth quarter 2019 (2019 Base Rate Case). The ultimate outcome of this matter cannot be determined at this time.
Pursuant to the PEP Settlement Agreement, Mississippi Power's performance-adjusted allowed ROE will be 9.31% and its allowed equity ratio will remain at 50%, pending further review by the Mississippi PSC. In lieu of the requested equity ratio increase, Mississippi Power will retain $44 million of excess accumulated deferred income taxes resulting from the Tax Reform Legislation, which had been proposed to be amortized beginning in 2018, until the conclusion of the 2019 Base Rate Case. Further, Mississippi Power will seek equity contributions sufficient to restore its equity ratio (which was 43.5% at June 30, 2018) to the 50% target. In the event Mississippi Power's actual average equity ratio for 2018 is more than 1% higher or lower than the 50% target, Mississippi Power will defer the corresponding difference in its revenue requirement as a regulatory asset or liability for resolution in the 2019 Base Rate Case.
Pursuant to the PEP Settlement Agreement, PEP proceedings will be suspended until after the conclusion of the 2019 Base Rate Case and Mississippi Power will not be required to make any PEP filings for regulatory years 2018, 2019, and 2020. The PEP Settlement Agreement also resolves all open PEP filings with no change to customer rates. As a result, in the third quarter 2018, Mississippi Power expects to recognize revenues of $5 million previously reserved in connection with the 2012 PEP lookback filing.
Energy Efficiency
On May 8, 2018, the Mississippi PSC issued an order approving Mississippi Power's revised annual projected Energy Efficiency Cost Rider 2018 compliance filing, submitted on May 3, 2018, which increased annual retail revenues by approximately $3 million effective with the first billing cycle for June 2018.
Environmental Compliance Overview Plan
On August 3, 2018, Mississippi Power and the MPUS entered into a settlement agreement with respect to the 2018 ECO Plan filing (ECO Settlement Agreement), which provides for an increase of approximately $17 million in annual base retail revenues and was approved by the Mississippi PSC on August 7, 2018. Rates under the ECO Settlement Agreement will take effect for the first billing cycle of September 2018 and will continue in effect until modified by the Mississippi PSC. These revenues are expected to be sufficient to recover the costs included in Mississippi Power's request for 2018, as well as the remaining deferred amounts that were originally expected to be recovered in 2019. In accordance with the ECO Settlement Agreement, ECO Plan proceedings will be suspended until after the conclusion of the 2019 Base Rate Case and Mississippi Power will not be required to make any ECO Plan filings for 2018, 2019, and 2020, with any necessary true-ups to be reflected in the 2019 Base Rate Case. The ECO Settlement Agreement contains the same terms as the PEP Settlement Agreement described herein with respect to allowed ROE and equity ratio.
Ad Valorem Tax Adjustment
On May 8, 2018, the Mississippi PSC approved Mississippi Power's annual ad valorem tax adjustment factor filing for 2018, which included an annual rate increase of 0.8%, or $7 million, in annual retail revenues effective with the first billing cycle for June 2018, primarily due to increased assessments.

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
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Southern Company Gas
See Note 3 to the financial statements of Southern Company and Southern Company Gas under "Regulatory Matters – Southern Company Gas" and "Regulatory Matters," respectively, in Item 8 of the Form 10-K for additional information regarding Southern Company Gas' regulatory matters.
Riders
On April 19, 2018, the Illinois Commission approved Nicor Gas' variable income tax adjustment rider. This rider provides for refund or recovery of changes in income tax expense that result from income tax rates that differ from those used in Nicor Gas' last rate case. Customer refunds began on July 1, 2018 related to the January 1, 2018 through May 4, 2018 impacts of the Tax Reform Legislation. The impact of the Tax Reform Legislation subsequent to May 4, 2018 was addressed in Nicor Gas' approved rehearing request discussed herein under "Settled Base Rate Cases."
Natural Gas Cost Recovery
Southern Company Gas has established natural gas cost recovery rates approved by the relevant state regulatory agencies in the states in which it serves. Natural gas cost recovery revenues are adjusted for differences in actual recoverable natural gas costs and amounts billed in current regulated rates. Changes in the billing factor will not have a significant effect on Southern Company's or Southern Company Gas' revenues or net income, but will affect cash flows.
Base Rate Cases
Settled Base Rate Cases
In October 2017, Florida City Gas filed a general base rate case with the Florida PSC requesting an annual revenue increase of $19 million, which included an interim rate increase of $5 million annually that was approved and became effective January 12, 2018, subject to refund. On March 26, 2018, the Florida PSC approved a settlement that, after including the impact of the Tax Reform Legislation, provides for an $11.5 million increase in annual base rate revenues, effective June 1, 2018, based on a ROE of 10.19%.
On February 23, 2018, Atlanta Gas Light revised its annual base rate filing to reflect the impacts of the Tax Reform Legislation and requested a $16 million rate reduction in 2018. On May 15, 2018, the Georgia PSC approved a stipulation for Atlanta Gas Light's annual base rates to remain at the 2017 level for 2018 and 2019, with customer credits of $8 million in each of July 2018 and October 2018 to reflect the impacts of the Tax Reform Legislation. The Georgia PSC maintained Atlanta Gas Light's previously authorized earnings band based on a ROE between 10.55% and 10.95% and increased the allowed equity ratio by 4% to an equity ratio of 55% to address the negative cash flow and credit metric impacts of the Tax Reform Legislation. Additionally, Atlanta Gas Light is required to file a traditional base rate case on or before June 1, 2019 for rates effective January 1, 2020.
On May 2, 2018, the Illinois Commission approved Nicor Gas' rehearing request for revised base rates to incorporate the reduction in the federal income tax rate as a result of the Tax Reform Legislation. The resulting decrease of approximately $44 million in annual base rate revenues became effective May 5, 2018. Nicor Gas' previously-authorized capital structure and ROE of 9.8% were not addressed in the rehearing and remain unchanged. The impact of the Tax Reform Legislation prior to May 5, 2018 was addressed in the variable income tax rider discussed herein under "Riders."

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

Pending Base Rate Case
On February 15, 2018, Chattanooga Gas filed a general base rate case with the Tennessee Public Utility Commission (PUC) requesting a $7 million increase in annual base rate revenues. The requested increase, which, in accordance with a Tennessee PUC order, incorporated the effects of the Tax Reform Legislation, was based on a projected test year ending June 30, 2019 and a ROE of 11.25%. The Tennessee PUC is expected to rule on the requested increase in the third quarter 2018.
The ultimate outcome of this matter cannot be determined at this time.
Other
The New Jersey BPU, Maryland PSC, and Virginia Commission each issued an order effective January 1, 2018 that requires utilities in their respective states to defer as a regulatory liability the impact of the Tax Reform Legislation, including the reduction in the corporate income tax rate to 21% and the impact of the flowback of excess deferred income taxes. On June 22, 2018, the New Jersey BPU approved a $12 million reduction in Elizabethtown Gas' annual base rate revenues. On March 28, 2018, the Maryland PSC approved a $0.1 million reduction in Elkton Gas' annual base rate revenues effective April 1, 2018. Credits were issued to customers in Maryland in May 2018 and will be issued to customers in New Jersey in the third quarter 2018 for the impact of the Tax Reform Legislation on the January 2018 through March 2018 billing periods.
On April 25, 2018, the Virginia Commission issued an order indicating that any proposal beyond a proposed base rate reduction to reflect the cost savings from the Tax Reform Legislation must be made through a general base rate case. Virginia Natural Gas expects to address the cost savings from the Tax Reform Legislation in the third quarter 2018 by filing an annual information form. The Virginia Commission is expected to rule on the impact of the Tax Reform Legislation by the first half of 2019. The ultimate outcome of this matter cannot be determined at this time.
Regulatory Infrastructure Programs
Southern Company Gas is engaged in various infrastructure programs that update or expand its gas distribution systems to improve reliability and help ensure the safety of its utility infrastructure, and recovers in rates its investment and a return associated with these infrastructure programs. See Note 3 to the financial statements of Southern Company and Southern Company Gas under "Regulatory Matters – Southern Company Gas – Regulatory Infrastructure Programs" and "Regulatory Matters – Regulatory Infrastructure Programs," respectively, in Item 8 of the Form 10-K for additional information.
Atlanta Gas Light's Pipeline Replacement Program
One of the capital projects under Atlanta Gas Light's Pipeline Replacement Program experienced construction issues and Atlanta Gas Light was required to complete mitigation work prior to placing it in service. In the first quarter 2018, Atlanta Gas Light recovered $7 million from the final settlement of contractor litigation claims. Mitigation costs recovered through the legal process are retained by Atlanta Gas Light. For additional information on the Pipeline Replacement Program settlement, see Note 3 to the financial statements of Southern Company Gas under "Regulatory Matters PRP Settlement" in Item 8 of the Form 10-K.Power.
Nuclear Construction(D) REVENUE FROM CONTRACTS WITH CUSTOMERS
See Note 3 to the financial statements of Southern Company and Georgia Power under "Nuclear Construction" and "Retail Regulatory Matters – Nuclear Construction," respectively, in Item 8 of the Form 10-K for additional information regarding Georgia Power's construction of Plant Vogtle Units 3 and 4, VCM reports, and the NCCR tariff.
In 2009, the Georgia PSC certified construction of Plant Vogtle Units 3 and 4. In 2012, the NRC issued the related combined construction and operating licenses, which allowed full construction of the two AP1000 nuclear units (with electric generating capacity of approximately 1,100 MWs each) and related facilities to begin. Until March 2017, construction on Plant Vogtle Units 3 and 4 continued under the Vogtle 3 and 4 Agreement, which was a

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
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substantially fixed price agreement. In March 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code.
In connection with the EPC Contractor's bankruptcy filing, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into the Interim Assessment Agreement with the EPC Contractor to allow construction to continue. The Interim Assessment Agreement expired in July 2017 when Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the EPC Contractor entered into the Vogtle Services Agreement. Under the Vogtle Services Agreement, Westinghouse provides facility design and engineering services, procurement and technical support, and staff augmentation on a time and materials cost basis. The Vogtle Services Agreement will continue until the start-up and testing of Plant Vogtle Units 3 and 4 are complete and electricity is generated and sold from both units. The Vogtle Services Agreement is terminable by the Vogtle Owners upon 30 days' written notice.
In October 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into a construction completion agreement with Bechtel, whereby Bechtel will serve as the primary contractor for the remaining construction activities for Plant Vogtle Units 3 and 4 (Bechtel Agreement). The Bechtel Agreement is a cost reimbursable plus fee arrangement, whereby Bechtel is reimbursed for actual costs plus a base fee and an at-risk fee, which is subject to adjustment based on Bechtel's performance against cost and schedule targets. Each Vogtle Owner is severally (not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to Bechtel under the Bechtel Agreement. The Vogtle Owners may terminate the Bechtel Agreement at any time for their convenience, provided that the Vogtle Owners will be required to pay amounts related to work performed prior to the termination (including the applicable portion of the base fee), certain termination-related costs, and, at certain stages of the work, the applicable portion of the at-risk fee. Bechtel may terminate the Bechtel Agreement under certain circumstances, including certain Vogtle Owner suspensions of work, certain breaches of the Bechtel Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events. Pursuant to the Loan Guarantee Agreement between Georgia Power and the DOE, Georgia Power is required to obtain the DOE's approval of the Bechtel Agreement prior to obtaining any further advances under the Loan Guarantee Agreement.
In December 2017, the Georgia PSC approved Georgia Power's seventeenth VCM report, which included a recommendation to continue construction of Plant Vogtle Units 3 and 4, with Southern Nuclear serving as project manager and Bechtel serving as the primary construction contractor.
Cost and Schedule
In preparation for its nineteenth VCM filing, Georgia Power requested Southern Nuclear to perform a full cost reforecast for the project. Georgia Power's approximate proportionate share of the remaining estimated capital cost to complete Plant Vogtle Units 3 and 4 by the expected in-service dates of November 2021 and November 2022, respectively, is as follows:
 (in billions)
Base project capital cost forecast(a)(b)
$8.0
Construction contingency estimate0.4
Total project capital cost forecast(a)(b)
8.4
Net investment as of June 30, 2018(b)
(4.0)
Remaining estimate to complete(a)
$4.4
(a)Excludes financing costs expected to be capitalized through AFUDC of approximately $350 million.
(b)Net of $1.7 billion received from Toshiba in 2017 under the Guarantee Settlement Agreement and $188 million in Customer Refunds recognized as a regulatory liability in 2017.
Georgia Power estimates that its financing costs for construction of Plant Vogtle Units 3 and 4 will total approximately $3.2 billion, of which $1.7 billion had been incurred through June 30, 2018.

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
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The $0.7 billion increase to the base capital cost forecast reflected in the table above primarily results from changed assumptions related to the finalization of contract scopes and management responsibilities for Bechtel and over 60 subcontractors, labor productivity rates, and craft labor incentives, as well as the related levels of project management, oversight, and support, including field supervision and engineering support.
Although Georgia Power believes these incremental costs are reasonable and necessary to complete the project and the Georgia PSC's order in the seventeenth VCM proceeding specifically states that the construction of Plant Vogtle Units 3 and 4 is not subject to a cost cap, Georgia Power does not intend to seek rate recovery for these cost increases included in the current base capital cost forecast (or any related financing costs), which will be filed with the Georgia PSC in the nineteenth VCM report at the end of August 2018. In connection with future VCM filings, Georgia Power may request the Georgia PSC to evaluate costs currently included in the construction contingency estimate for rate recovery as and when they are appropriately included in the base capital cost forecast. After considering the significant level of uncertainty that exists regarding the future recoverability of costs included in the construction contingency estimate since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in these future regulatory proceedings, Georgia Power has recorded a total pre-tax charge to income of $1.1 billion ($0.8 billion after tax), which includes the total increase in the capital cost forecast and construction contingency estimate as of June 30, 2018.
Subsequent to the EPC Contractor bankruptcy filing, a number of subcontractors to the EPC Contractor alleged non-payment by the EPC Contractor for amounts owed for work performed on Plant Vogtle Units 3 and 4. Georgia Power, acting for itself and as agent for the Vogtle Owners, has taken actions to remove liens filed by these subcontractors through the posting of surety bonds. Related to such liens, certain subcontractors have filed, and additional subcontractors may file, lawsuits against the EPC Contractor and the Vogtle Owners to preserve their payment rights with respect to such claims. All known amounts associated with the removal of subcontractor liens and other EPC Contractor pre-petition accounts payable have been paid or accrued as of June 30, 2018. The ultimate liability is expected to be finalized in connection with the completion of the sale of Westinghouse.
As construction continues, challenges with management of contractors, subcontractors, and vendors; labor productivity, availability, and/or cost escalation; procurement, fabrication, delivery, assembly, and/or installation, including any required engineering changes, of plant systems, structures, and components (some of which are based on new technology that is just beginning initial operation in the global nuclear industry at this scale); or other issues could arise and change the projected schedule and estimated cost.
There have been technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4 at the federal and state level and additional challenges may arise. Processes are in place that are designed to assure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating licenses, including inspections by Southern Nuclear and the NRC that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the NRC. Various design and other licensing-based compliance matters, including the timely resolution of Inspections, Tests, Analyses, and Acceptance Criteria and the related approvals by the NRC, may arise, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs.
The ultimate outcome of these matters cannot be determined at this time. However, any extension of the project schedule is currently estimated to result in additional base capital costs of approximately $50 million per month, based on Georgia Power's ownership interests, and AFUDC of approximately $12 million per month. While Georgia Power is not precluded from seeking recovery of any future capital cost forecast increase, management will ultimately determine whether or not to seek recovery. Any further changes to the capital cost forecast that are not expected to be recoverable through regulated rates will be required to be charged to income and such charges could be material.

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

Joint Owner Contracts
In November 2017, the Vogtle Owners entered into an amendment to their joint ownership agreements for Plant Vogtle Units 3 and 4 (as amended, Vogtle Joint Ownership Agreements) to provide for, among other conditions, additional Vogtle Owner approval requirements. Pursuant to the Vogtle Joint Ownership Agreements, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction if certain adverse events occur, including: (i) the bankruptcy of Toshiba; (ii) termination or rejection in bankruptcy of certain agreements, including the Vogtle Services Agreement or the Bechtel Agreement; (iii) the Georgia PSC or Georgia Power determines that any of Georgia Power's costs relating to the construction of Plant Vogtle Units 3 and 4 will not be recovered in retail rates because such costs are deemed unreasonable or imprudent; or (iv) an increase in the construction budget contained in the seventeenth VCM report of more than $1 billion or extension of the project schedule contained in the seventeenth VCM report of more than one year. In addition, pursuant to the Vogtle Joint Ownership Agreements, the required approval of holders of ownership interests in Plant Vogtle Units 3 and 4 is at least (i) 90% for a change of the primary construction contractor and (ii) 67% for material amendments to the Vogtle Services Agreement or agreements with Southern Nuclear or the primary construction contractor, including the Bechtel Agreement. The Vogtle Joint Ownership Agreements also confirm that the Vogtle Owners' sole recourse against Georgia Power or Southern Nuclear for any action or inaction in connection with their performance as agent for the Vogtle Owners is limited to removal of Georgia Power and/or Southern Nuclear as agent, except in cases of willful misconduct.
As a result of the increase in the total project capital cost forecast and Georgia Power's decision not to seek rate recovery of the increase in the base capital costs as described in "Cost and Schedule" herein, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction. The Vogtle Owners are expected to conduct these votes in the third quarter 2018.
If the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 do not vote to continue construction, the Vogtle Joint Ownership Agreements provide that the project will be cancelled, and construction will cease. In the event that fewer than 90% of the Vogtle Owners vote to continue construction, Georgia Power and the other Vogtle Owners will assess options for Plant Vogtle Units 3 and 4. If Plant Vogtle Units 3 and 4 were cancelled and Georgia Power was unable to recover costs it has incurred in connection with the project, Southern Company's and Georgia Power's results of operations, cash flow, and financial condition would be materially impacted. The ultimate outcome of this matter cannot be determined at this time.
Regulatory Matters
In 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3 and 4 with a certified capital cost of $4.418 billion. In addition, in 2009 the Georgia PSC approved inclusion of the Plant Vogtle Units 3 and 4 related CWIP accounts in rate base, and the State of Georgia enacted the Georgia Nuclear Energy Financing Act, which allows Georgia Power to recover financing costs for Plant Vogtle Units 3 and 4. Financing costs are recovered on all applicable certified costs through annual adjustments to the NCCR tariff up to the certified capital cost of $4.418 billion. As of June 30, 2018, Georgia Power had recovered approximately $1.7 billion of financing costs. Financing costs related to capital costs above $4.418 billion will be recovered through AFUDC; however, Georgia Power will not record AFUDC related to any capital costs in excess of the total deemed reasonable by the Georgia PSC (currently $7.3 billion) and not requested for rate recovery.
Georgia Power is required to file semi-annual VCM reports with the Georgia PSC by February 28 and August 31 of each year. In 2013, in connection with the eighth VCM report, the Georgia PSC approved a stipulation between Georgia Power and the staff of the Georgia PSC to waive the requirement to amend the Plant Vogtle Units 3 and 4 certificate in accordance with the 2009 certification order until the completion of Plant Vogtle Unit 3, or earlier if deemed appropriate by the Georgia PSC and Georgia Power.
In 2016, the Georgia PSC voted to approve a settlement agreement (Vogtle Cost Settlement Agreement) resolving certain prudency matters in connection with the fifteenth VCM report. In December 2017, the Georgia PSC voted to approve (and issued its related order on January 11, 2018) certain recommendations made by Georgia Power in the

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

seventeenth VCM report and modifying the Vogtle Cost Settlement Agreement. The Vogtle Cost Settlement Agreement, as modified by the January 11, 2018 order, resolved the following regulatory matters related to Plant Vogtle Units 3 and 4: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report should be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement was reasonable and prudent and none of the amounts paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) (a) capital costs incurred up to $5.68 billion would be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, (b) Georgia Power would have the burden to show that any capital costs above $5.68 billion were prudent, and (c) a revised capital cost forecast of $7.3 billion (after reflecting the impact of payments received under the Guarantee Settlement Agreement and Customer Refunds) was found reasonable; (iv) construction of Plant Vogtle Units 3 and 4 should be completed, with Southern Nuclear serving as project manager and Bechtel as primary contractor; (v) approved and deemed reasonable Georgia Power's revised schedule placing Plant Vogtle Units 3 and 4 in service in November 2021 and November 2022, respectively; (vi) confirmed that the revised cost forecast does not represent a cost cap and that prudence decisions on cost recovery will be made at a later date, consistent with applicable Georgia law; (vii) reduced the ROE used to calculate the NCCR tariff (a) from 10.95% (the ROE rate setting point authorized by the Georgia PSC in the 2013 ARP) to 10.00% effective January 1, 2016, (b) from 10.00% to 8.30%, effective January 1, 2020, and (c) from 8.30% to 5.30%, effective January 1, 2021 (provided that the ROE in no case will be less than Georgia Power's average cost of long-term debt); (viii) reduced the ROE used for AFUDC equity for Plant Vogtle Units 3 and 4 from 10.00% to Georgia Power's average cost of long-term debt, effective January 1, 2018; and (ix) agreed that upon Unit 3 reaching commercial operation, retail base rates would be adjusted to include carrying costs on those capital costs deemed prudent in the Vogtle Cost Settlement Agreement. The January 11, 2018 order also stated that if Plant Vogtle Units 3 and 4 are not commercially operational by June 1, 2021 and June 1, 2022, respectively, the ROE used to calculate the NCCR tariff will be further reduced by 10 basis points each month (but not lower than Georgia Power's average cost of long-term debt) until the respective unit is commercially operational. The ROE reductions negatively impacted earnings by approximately $25 million in 2017 and are estimated to have negative earnings impacts of approximately $100 million in 2018 and an aggregate of $585 million from 2019 to 2022.
In its January 11, 2018 order, the Georgia PSC also stated if other conditions change and assumptions upon which Georgia Power's seventeenth VCM report are based do not materialize, the Georgia PSC reserved the right to reconsider the decision to continue construction.
On February 12, 2018, Georgia Interfaith Power & Light, Inc. and Partnership for Southern Equity, Inc. filed a petition appealing the Georgia PSC's January 11, 2018 order with the Fulton County Superior Court. On March 8, 2018, Georgia Watch filed a similar appeal to the Fulton County Superior Court for judicial review of the Georgia PSC's final decision and denial of Georgia Watch's motion for reconsideration. Georgia Power believes the two appeals have no merit; however, an adverse outcome in either appeal could have a material impact on Southern Company's and Georgia Power's results of operations, financial condition, and liquidity.
The Georgia PSC has approved seventeen VCM reports covering the periods through June 30, 2017, including total construction capital costs incurred through that date of $4.4 billion. On August 21, 2018, the Georgia PSC is scheduled to vote on Georgia Power's eighteenth VCM report, which requested approval of $448 million of construction capital costs (excluding the $1.7 billion received from Toshiba under the Guarantee Settlement Agreement and the $188 million in Customer Refunds recognized as a regulatory liability) incurred from July 1, 2017 through December 31, 2017.
On August 31, 2018, Georgia Power will file its nineteenth VCM report with the Georgia PSC, which will reflect the revised capital cost forecast discussed previously and request approval of $578 million of construction capital costs incurred from January 1, 2018 through June 30, 2018.
The ultimate outcome of these matters cannot be determined at this time.

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

DOE Financing
As of June 30, 2018, Georgia Power had borrowed $2.6 billion related to Plant Vogtle Units 3 and 4 costs through the Loan Guarantee Agreement and a multi-advance credit facility among Georgia Power, the DOE, and the FFB, which provides for borrowings of up to $3.46 billion, subject to the satisfaction of certain conditions. In September 2017, the DOE issued a conditional commitment to Georgia Power for up to approximately $1.67 billion in additional guaranteed loans under the Loan Guarantee Agreement. In June 2018, the DOE approved a request by Georgia Power to extend the conditional commitment to September 30, 2018. Any further extension must be approved by the DOE. Final approval and issuance of these additional loan guarantees by the DOE cannot be assured and are subject to the negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of other conditions, including the Vogtle Owners' votes to continue construction. See Note 6 to the financial statements of Southern Company and Georgia Power under "DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K and Note (F) under "DOE Loan Guarantee Borrowings" for additional information, including applicable covenants, events of default, mandatory prepayment events (including any decision not to continue construction of Plant Vogtle Units 3 and 4), and conditions to borrowing.
The ultimate outcome of these matters cannot be determined at this time.
Kemper County Energy Facility
For additional information on the Kemper County energy facility, see Note 3 to the financial statements of Southern Company and Mississippi Power under "Kemper County Energy Facility" in Item 8 of the Form 10-K.
As the mining permit holder for the Kemper County energy facility, Liberty Fuels Company, LLC has a legal obligation to perform mine reclamation, and Mississippi Power has a contractual obligation to fund all reclamation activities. Mine reclamation began in the first quarter 2018. See Note 1 to the financial statements of Southern Company and Mississippi Power under "Asset Retirement Obligations and Other Costs of Removal" and of Mississippi Power under "Variable Interest Entities" in Item 8 of the Form 10-K for additional information.
As of June 30, 2018, Mississippi Power recorded charges to income of an immaterial amount for the second quarter 2018 and $45 million ($33 million after tax) for year-to-date 2018, primarily resulting from the abandonment and related closure activities for the mine and gasifier-related assets at the Kemper County energy facility. Additional closure costs for the mine and gasifier-related assets, currently estimated to cost up to $25 million pre-tax (excluding salvage, net of dismantlement costs), are expected to be incurred during the remainder of 2018 and 2019. In addition, period costs, including, but not limited to, costs for compliance and safety, ARO accretion, and property taxes for the mine and gasifier-related assets, are estimated at $4 million for the remainder of 2018, $7 million in 2019, and $4 million annually beginning in 2020. The ultimate outcome of this matter cannot be determined at this time.
Reserve Margin Plan
On August 6, 2018, Mississippi Power filed its proposed RMP, as required by the Mississippi PSC's order in the docket established for the purposes of pursuing a global settlement of the costs related to the Kemper County energy facility. Under the RMP, Mississippi Power proposes alternatives that would reduce its reserve margin, with the most economic of the alternatives being the 2-year and 7-year acceleration of the retirement of Plant Watson Units 4 and 5, respectively, to the first quarter 2022 and the 4-year acceleration of the retirement of Plant Greene County Units 1 and 2 to the third quarter 2021 and the third quarter 2022, respectively, in order to lower or avoid operating costs. The Plant Greene County unit retirements would require the completion by Alabama Power of proposed transmission and system reliability improvements, as well as agreement by Alabama Power. The RMP filing also states that, in the event the Mississippi PSC ultimately approves an alternative that includes an accelerated retirement, Mississippi Power would require authorization to defer in a regulatory asset for future recovery the remaining net book value of the units at the time of retirement. Mississippi Power expects the MPUS and other interested parties to review the proposal prior to resolution by the Mississippi PSC. The ultimate outcome of this matter cannot be determined at this time. However, if approved by the Mississippi PSC, the alternatives are not expected to have any adverse impact on customer rates.

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

Other Matters
Investments in Leveraged Leases
See Note 1 to the financial statements of Southern Company under "Leveraged Leases" in Item 8 of the Form 10-K for additional information regarding a Southern Company Holdings Inc. (Southern Holdings) subsidiary's leveraged lease agreements and concerns about the financial and operational performance of one of the lessees and the associated generation assets.
The ability of the lessees to make required payments to the Southern Holdings subsidiary is dependent on the operational performance of the assets. As a result of operational improvements in the first half of 2018, the June 2018 lease payment was paid in full and the December 2018 lease payment is currently expected to be paid in full. However, operational issues and the resulting cash liquidity challenges persist and significant concerns continue regarding the lessee's ability to make the remaining semi-annual lease payments. These operational challenges may also impact the expected residual value of the assets at the end of the lease term in 2047. If any future lease payment is not paid in full, the Southern Holdings subsidiary may be unable to make its corresponding payment to the holders of the underlying non-recourse debt related to the generation assets. Failure to make the required payment to the debtholders would represent an event of default that would give the debtholders the right to foreclose on, and take ownership of, the generation assets from the Southern Holdings subsidiary, in effect terminating the lease and resulting in the write-off of the related lease receivable, which would result in a reduction in net income of approximately $86 million after tax based on the lease receivable balance as of June 30, 2018. Southern Company has evaluated the recoverability of the lease receivable and the expected residual value of the generation assets at the end of the lease under various scenarios and has concluded that its investment in the leveraged lease is not impaired as of June 30, 2018. Southern Company will continue to monitor the operational performance of the underlying assets and evaluate the ability of the lessee to continue to make the required lease payments. The ultimate outcome of this matter cannot be determined at this time.
Natural Gas Storage
A wholly-owned subsidiary of Southern Company Gas owns and operates a natural gas storage facility consisting of two salt dome caverns in Louisiana. Periodic integrity tests are required in accordance with rules of the Louisiana Department of Natural Resources (DNR). In August 2017, in connection with an ongoing integrity project, updated seismic mapping indicated the proximity of one of the caverns to the edge of the salt dome may be less than the required minimum and could result in Southern Company Gas retiring the cavern early. At June 30, 2018, the facility's property, plant, and equipment had a net book value of $111 million, of which the cavern itself represents approximately 20%. A potential early retirement of this cavern is dependent upon several factors including compliance with an order from the Louisiana DNR detailing the requirements to place the cavern back in service, which includes, among other things, obtaining core samples to determine the composition of the sheath surrounding the edge of the salt dome.
The cavern continues to maintain its pressures and overall structural integrity. Southern Company Gas intends to monitor the cavern and comply with the Louisiana DNR order through 2020 and place the cavern back in service in 2021. These events were considered in connection with Southern Company Gas' 2017 long-lived asset impairment analysis, which determined there was no impairment. Any future changes in results of monitoring activities, rates at which expiring capacity contracts are re-contracted, timing of placing the cavern back in service, or Louisiana DNR requirements could trigger impairment. Further, early retirement of the cavern could trigger impairment of other long-lived assets associated with the natural gas storage facility. The ultimate outcome of this matter cannot be determined at this time, but could have a significant impact on Southern Company's financial statements and a material impact on Southern Company Gas' financial statements.
(C)REVENUE FROM CONTRACTS WITH CUSTOMERS
The registrants generate revenues from a variety of sources, some of which are excluded from the scope of ASC 606, Revenue from Contracts with Customers (ASC 606), such as leases, derivatives, and certain cost recovery mechanisms. See Note (A)1 to the financial statements under "Recently"Recently Adopted

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

Accounting StandardsRevenue"Revenue" in Item 8 of the Form 10-K for additional information on the adoption of ASC 606 for revenue from contracts with customers.
The majoritycustomers and Note 1 to the financial statements under "Revenues" and "Other Taxes" in Item 8 of the revenuesForm 10-K for additional information on the revenue policies of the traditional electric operating companiesregistrants. 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 are generated from contracts with retail electric andGas" in Item 8 of the Form 10-K for alternative revenue programs at the natural gas distribution customers. Revenues from this integrated service to deliver electricity or gas whenutilities, and if called upon by the customer is recognized as a single performance obligation satisfied over time and is recognized at a tariff rate as electricity or gas is deliveredNote 2 to the customer during the month. The traditional electric operating companies and Southern Company Gas exclude taxes imposed on the customer and collected on behalf of governmental agencies to be remitted to these agencies from the transaction pricefinancial statements in determining the revenue related to contracts with a customer.
The traditional electric operating companies and Southern Power also have contracts with multiple performance obligations, such as capacity and energy in a wholesale PPA, where the contract's total transaction price is allocated to each performance obligation based on the standalone selling price. The standalone selling price is primarily determined by the price charged to customers for the specific goods or services transferred with the performance obligations. Generally, the registrants recognize revenue as the performance obligations are satisfied over time as electricity or natural gas is delivered to the customer or as generation capacity is available to the customer. At Southern Company Gas, the performance obligations related to wholesale gas services are satisfied, and revenue is recognized, at a point in time when natural gas is delivered to the customer.
The registrants generally have a right to consideration in an amount that corresponds directly with the value to the customerItem 8 of the entity's performance completed to date and may recognize revenue in the amount to which the entity has a right to invoice and has elected to recognize revenueForm 10-K for its salescost recovery mechanisms.

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Table of electricity, capacity, and natural gas using the invoice practical expedient. In addition, payment for goods and services rendered is typically due in the subsequent month following satisfaction of the registrants' performance obligation.Contents

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

The following tables disaggregate revenue sources for the three and six months ended June 30,March 31, 2019 and 2018:
For the Three Months Ended June 30, 2018
For the Six
Months Ended June 30, 2018
For the Three
Months Ended March 31, 2019
For the Three Months Ended March 31, 2018
(in millions)(in millions)
Southern Company  
Operating revenues  
Retail electric revenues(a)
  
Residential$1,579
$3,118
$1,288
$1,539
Commercial1,315
2,557
1,093
1,243
Industrial814
1,569
677
756
Other32
64
26
30
Natural gas distribution revenues642
1,865
1,163
1,224
Alternative revenue programs(b)
(4)(27)(2)(24)
Total retail electric and gas distribution revenues$4,378
$9,146
$4,245
$4,768
Wholesale energy revenues(c)(d)
459
928
367
472
Wholesale capacity revenues(d)
152
302
132
151
Other natural gas revenues(e)(f)
68
476
313
407
Other revenues(f)(g)
570
1,147
355
574
Total operating revenues$5,627
$11,999
$5,412
$6,372
(a)
Retail electric revenues include $8 million and $18 million and $36 million of revenues accounted for as leases for the three and six months ended June 30,March 31, 2019 and 2018, respectively, and a (net reduction) or net increase of $68$(103) million and $101$117 million for the three and six months ended June 30,March 31, 2019 and 2018, respectively, from certain cost recovery mechanisms that are not accounted for as revenue under ASC 606. See Note 3 to the financial statements of Southern Company under "Regulatory Matters" in Item 8 of the Form 10-K for additional information on cost recovery mechanisms.
(b)See Note 1 to the financial statements of Southern Company under "Revenues" in Item 8 of the Form 10-K for additional information on alternative revenue programs at the natural gas distribution utilities. Alternative revenue program revenues are presented net of any previously recognized program amounts billed to customers during the same accounting period.
(c)Wholesale energy revenues include $61$53 million and $155$93 million for the three and six months ended June 30,March 31, 2019 and 2018, respectively, of revenues accounted for as derivatives, primarily related to physical energy sales in the wholesale electricity market. See Note (I) for additional information on energy-related derivative contracts.
(d)Wholesale energy and wholesale capacity revenues include $118$66 million and $31$25 million, respectively, for the three months ended June 30, 2018March 31, 2019 and $187$69 million and $61$30 million, respectively, for the sixthree months ended June 30,March 31, 2018 of PPA contractsrelated to PPAs accounted for as leases.
(e)
Other natural gas revenues related to Southern Company Gas' energy and risk management activities are presented net of the related costs of those activities and include gross third-party revenues of $1.3$1.9 billion for each of the three months ended March 31, 2019 and 2018, of which $1.2 billion and $3.3 billion for the three and six months ended June 30, 2018, respectively, of which $0.7 billion and $1.8$1.1 billion, respectively, relates to contracts that are accounted for as derivatives. See Note (L)(M) under "Southern Company Gas" for additional information on the components of wholesale gas services operating revenues.
(f)Other natural gas revenues for the three months ended March 31, 2019 include $9 million of revenues accounted for as leases.
(g)Other revenues include $89$96 million and $183$90 million for the three and six months ended June 30,March 31, 2019 and 2018, respectively, of revenues not accounted for under ASC 606.606, including $31 million and $33 million in 2019 and 2018, respectively, accounted for as leases.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

Alabama PowerGeorgia Power
Gulf
Power
Mississippi PowerAlabama PowerGeorgia PowerMississippi Power
(in millions)(in millions)
For the Three Months Ended June 30, 2018 
For the Three Months Ended March 31, 2019 
Operating revenues  
Retail revenues(a)(b)
  
Residential$557
$785
$172
$65
$540
$688
$60
Commercial402
749
96
68
354
674
65
Industrial372
335
31
76
313
289
74
Other7
20
2
3
6
17
4
Total retail electric revenues$1,338
$1,889
$301
$212
$1,213
$1,668
$203
Wholesale energy revenues(c)
71
26
21
73
94
18
78
Wholesale capacity revenues25
13
6
1
27
14
1
Other revenues(b)(d)
69
120
16
11
74
133
5
Total operating revenues$1,503
$2,048
$344
$297
$1,408
$1,833
$287
  
For the Six Months Ended June 30, 2018 
For the Three Months Ended March 31, 2018 
Operating revenues  
Retail revenues(a)(b)
  
Residential$1,127
$1,529
$337
$125
$570
$744
$60
Commercial774
1,466
188
130
371
717
62
Industrial710
650
63
146
338
316
70
Other13
43
3
5
6
21
2
Total retail electric revenues$2,624
$3,688
$591
$406
$1,285
$1,798
$194
Wholesale energy revenues(c)
172
66
56
167
101
40
98
Wholesale capacity revenues49
27
12
5
24
14
4
Other revenues(b)(d)
131
227
33
20
63
109
6
Total operating revenues$2,976
$4,008
$692
$598
$1,473
$1,961
$302
(a)Retail revenues at Alabama Power, Georgia Power, Gulf Power, and Mississippi Power include a net increase or (net reduction) of $78$(57) million, $3 million, $(12)$(47) million, and $(1)$1 million, respectively, for the three months ended June 30, 2018March 31, 2019 and $125$47 million, $12 million, $(28)$10 million, and $(8)$76 million, respectively, for the sixthree months ended June 30,March 31, 2018 related to certain cost recovery mechanisms that are not accounted for as revenue under ASC 606. See Note 3 to the financial statements of Alabama Power, Georgia Power, Gulf Power, and Mississippi Power under "Retail Regulatory Matters" in Item 8 of the Form 10-K for additional information on cost recovery mechanisms.
(b)
Retail revenues and other revenues at Georgia Power include$8 million and $11 million, respectively, for the three months ended March 31, 2019 and $18 million and $33 million, respectively, for the three months ended June 30, 2018 and $36 million and $66 million, respectively, for the six months ended June 30,March 31, 2018 of revenues accounted for as leases.
(c)Wholesale energy revenues at Alabama Power, and Georgia Power, and Mississippi Power include $3 million, $4 million, and $5$1 million, respectively, for the three months ended June 30, 2018March 31, 2019 and $9$5 million, $7 million, and $13$1 million, respectively, for the sixthree months ended June 30,March 31, 2018 accounted for as derivatives primarily related to physical energy sales in the wholesale electricity market. See Note (I) for additional information on energy-related derivative contracts.
(d)Other revenues at Alabama Power and Georgia Power and Gulf Power include $26 million, $26$28 million and $2$31 million, respectively, for the three months ended June 30, 2018March 31, 2019 and $52 million, $53$25 million and $4$26 million, respectively, for the sixthree months ended June 30,March 31, 2018 of revenues not accounted for under ASC 606.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

For the Three Months Ended June 30, 2018
For the Six
Months Ended June 30, 2018
For the Three
Months Ended March 31, 2019
For the Three
Months Ended March 31, 2018
(in millions)(in millions)
Southern Power  
PPA capacity revenues(a)
$144
$282
$127
$138
PPA energy revenues(a)
302
556
227
254
Non-PPA revenues(b)
106
221
85
115
Other revenues3
5
4
2
Total operating revenues$555
$1,064
$443
$509
(a)PPA capacity revenues and PPA energy revenues include $47$41 million and $127$72 million, respectively, for the three months ended June 30, 2018March 31, 2019 and $94$47 million and $203$76 million, respectively, for the sixthree months ended June 30,March 31, 2018 related to PPAs accounted for as leases. See Note 1 to the financial statements of Southern Power under "Revenues" in Item 8 of the Form 10-K for additional information on capacity revenues accounted for as leases.
(b)Non-PPA revenues include $50$45 million and $129$79 million for the three and six months ended June 30,March 31, 2019 and 2018, respectively, of revenues from short-term sales related to physical energy sales from uncovered capacity in the wholesale electricity market. See Note 1 to the financial statements of Southern Power under "Revenues" in Item 8 of the Form 10-K and Note (I) for additional information on energy-related derivative contracts.
For the Three Months Ended June 30, 2018
For the Six
Months Ended June 30, 2018
For the Three
Months Ended March 31, 2019
For the Three
Months Ended March 31, 2018
(in millions)(in millions)
Southern Company Gas  
Operating revenues  
Natural gas distribution revenues  
Residential$273
$933
$601
$660
Commercial76
268
170
192
Transportation7
24
256
277
Industrial228
505
17
17
Other58
135
119
78
Alternative revenue programs(a)
(4)(27)(2)(24)
Total natural gas distribution revenues$638
$1,838
$1,161
$1,200
Gas marketing services(b)
89
359
Gas pipeline investments(b)
8
8
Wholesale gas services(c)
(15)131
66
146
Gas midstream operations18
40
Gas marketing services(d)
229
271
Other revenues
1
10
14
Total operating revenues$730
$2,369
$1,474
$1,639
(a)See Note 1 to the financial statements of Southern Company Gas under "Revenues" in Item 8 of the Form 10-K for additional information on alternative revenue programs at the natural gas distribution utilities. Alternative revenue program revenues are presented net of any previously recognized program amounts billed to customers during the same accounting period.
(b)Gas marketing services includes $4Revenues from gas pipeline investments include $8 million for the sixthree months ended June 30, 2018 of revenues notMarch 31, 2019 accounted for under ASC 606.as leases.
(c)
Wholesale gas services revenues are presented net of the related costs associated with its energy trading and risk management activities. Operating revenues, as presented, include gross third-party revenues of $1.3$1.9 billion for each of the three months ended March 31, 2019 and 2018, of which $1.2 billion and $3.3 billion for the three and six months ended June 30, 2018, respectively, of which $0.7 billion and $1.8$1.1 billion, respectively, relates to contracts that are accounted for as derivatives. See Note (L)(M) under "Southern Company Gas" for additional information on the components of wholesale gas services operating revenues and Note (I) for additional information on energy-related derivative contracts.revenues.
(d)Gas marketing services includes $6 million and $4 million for the three months ended March 31, 2019 and 2018, respectively, of revenues not accounted for under ASC 606.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

Contract Balances
The following table reflects the closing balances of receivables, contract assets, and contract liabilities related to revenues from contracts with customers as of June 30,March 31, 2019 and December 31, 2018:
Receivables Contract Assets Contract LiabilitiesReceivables Contract Assets Contract Liabilities
(in millions)March 31, 2019December 31, 2018 March 31, 2019December 31, 2018 March 31, 2019December 31, 2018
Southern Company$2,785
 $33
 $36
(in millions)
Southern Company(*)
$2,522
$2,630
 $84
$102
 $62
$32
Alabama Power603
 
 10
514
520
 1

 10
12
Georgia Power840
 9
 9
668
721
 41
58
 25
7
Gulf Power169
 
 1
Mississippi Power83
 
 
85
100
 

 

Southern Power136
 
 4
99
118
 

 4
11
Southern Company Gas570
 
 1
948
952
 

 1
2
(*)Includes amounts related to held for sale investments.
As of June 30,March 31, 2019 and December 31, 2018, Alabama Power had contract liabilities for outstanding performance obligations primarily related to extended service agreements. Georgia Power had contract assets primarily related to unregulated service agreements where payment is contingent on project completion. Georgia Power had contract liabilities for outstanding performance obligations primarily related tocompletion 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. Southern Company's unregulated distributed generation business had $23$34 million and $16$39 million of contract assets and $25 million and $11 million of contract liabilities at March 31, 2019 and December 31, 2018, respectively, remaining for outstanding performance obligations.
The following table reflects revenue from contracts with customers recognized in the three-month period ended March 31, 2019 included in the contract liability at December 31, 2018:
 Three Months Ended March 31, 2019
 (in millions)
Southern Company$17
Southern Power10
Revenues recognized in the three-month period ended March 31, 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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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

Remaining Performance Obligations
The traditional electric operating companies and Southern Power have long-term contracts with customers in which revenues are recognized aswhen the performance obligations are satisfied overduring 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. RevenuesRegistrants with revenues from contracts with customers related to these performance obligations remaining at June 30, 2018 are expectedMarch 31, 2019 expect the revenues to be recognized as follows:
20182019202020212022
2023 and
Thereafter
2019 (remaining)2020202120222023Thereafter
(in millions)(in millions)
Southern Company(*)
$263
$352
$322
$322
$310
$1,960
$451
$349
$315
$310
$301
$2,219
Alabama Power11
22
22
26
23
161
16
22
27
23
22
140
Georgia Power20
41
38
40
30
113
30
38
40
30
31
82
Gulf Power11
22




Mississippi Power2
3
3
1


2
3
1



Southern Power(*)
211
310
283
277
276
1,809
Southern Power248
295
270
276
269
2,143
(*)
ExcludesIncludes amounts related to held for sale assets. See Note (J) under "Southern Company's Sale of Gulf Power" and "Southern PowerSale of Florida Plants" for additional information.
investments.
(E) CONSOLIDATED ENTITIES AND EQUITY METHOD INVESTMENTS
Southern Power
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 VIEs.
Southern Power has certain wholly-owned 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. Southern Power previously consolidated SP Solar and SP Wind. Southern Power continues to consolidate them following the 2018 sales of noncontrolling interests in 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 March 31, 2019, SP Solar had total assets of $6.5 billion, total liabilities of $373 million, and noncontrolling interests of $1.2 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 March 31, 2019, SP Wind had total assets of $2.6 billion, total liabilities of $141 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

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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.
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.
Equity Method Investments
The carrying amounts of Southern Company Gas' equity method investments as of March 31, 2019 and December 31, 2018 and related income from those investments for the three-month periods ended March 31, 2019 and 2018 were as follows:
Investment BalanceMarch 31, 2019December 31, 2018
 (in millions)
SNG$1,262
$1,261
Atlantic Coast Pipeline96
83
PennEast Pipeline75
71
Other124
123
Total$1,557
$1,538
Earnings from Equity Method InvestmentsThree Months Ended
March 31, 2019
Three Months
Ended
March 31, 2018
 (in millions)
SNG$42
$39
Atlantic Coast Pipeline3
1
PennEast Pipeline2
1
Other1
1
Total$48
$42
SNG
Selected financial information of SNG for the three months ended March 31, 2019 and 2018 is as follows:
Income Statement Information
Three Months Ended
March 31, 2019
Three Months
Ended
March 31, 2018
 (in millions)
Revenues$166
$160
Operating income106
99
Net income84
78
(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 March 31, 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 March 31, 2019, the traditional electric operating companies had approximately $432 million (comprised of approximately $87 million at Alabama Power and $345 million at Georgia Power) of revenue bonds outstanding that were required to be remarketed within the next 12 months. Subsequent to March 31, 2019, Georgia Power purchased and held approximately $115 million of outstanding pollution control revenue bonds required to be remarketed. 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 March 31, 2019:
 Expires  
Company201920202022 Total 
Unused(d)
 (in millions)
Southern Company(a)
$
$
$2,000
 $2,000
 $1,999
Alabama Power33
500
800
 1,333
 1,333
Georgia Power

1,750
 1,750
 1,736
Mississippi Power100


 100
 100
Southern Power(b)


750
 750
 741
Southern Company Gas(c)


1,900
 1,900
 1,895
Other30


 30
 30
Southern Company Consolidated$163
$500
$7,200
 $7,863
 $7,834
(D)(a)FAIR VALUE MEASUREMENTSRepresents 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 $24 million was unused at March 31, 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 $1.4 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.
(d)Amounts used are for letters of credit.
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 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 March 31, 2019, Georgia Power had a total of $3.46 billion of borrowings outstanding under the FFB Credit Facilities.

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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.
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.

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Financing Activities
The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first three months of 2019:
CompanySenior 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 Power200
 
 
 
 
Georgia Power
 343
 108
 835
 2
Mississippi Power
 43
 
 
 
Other
 
 
 
 19
Southern Company Consolidated$2,300
 $386
 $108
 $835
 $21
(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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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.
Subsequent to March 31, 2019, Georgia Power purchased and held the following pollution control revenue bonds, which may be reoffered to the public at a later date:
$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.
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, that previously had been purchased and held by Mississippi Power.
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 March 31, 2019Three Months Ended March 31, 2018
 (in millions)
As reported shares1,038
1,011
Effect of stock-based compensation7
5
Diluted shares1,045
1,016
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 months ended March 31, 2019 and an immaterial amount of such awards was not included for the three months ended March 31, 2018.

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(G) INCOME TAXES
See Note 10 to the financial statements in Item 8 of the Form 10-K for additional tax information.
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 39.8% for the three months ended March 31, 2019 compared to 10.8% for the corresponding period in 2018. The effective tax rate increase was primarily due to the tax impact from the sale of Gulf Power. See Note (K) for additional information.
Alabama Power
Alabama Power's effective tax rate was 21.9% for the three months ended March 31, 2019 compared to 26.3% for the corresponding period in 2018. The effective tax rate decrease was primarily due to the application in 2018 of the accounting order approved by the Alabama PSC in May 2018 related to the Tax Reform Legislation. 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.
Mississippi Power
Mississippi Power's effective tax rate was 15.5% for the three months ended March 31, 2019 compared to a benefit rate of (34.7)% for the corresponding period in 2018. The effective tax rate increase was primarily due to lower estimated losses on the Kemper IGCC in 2019, partially offset by 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.
Southern Power
Southern Power's effective tax benefit rate was (49.8)% for the three months ended March 31, 2019 compared to (647.0)% for the corresponding period in 2018. The effective tax benefit rate decrease was primarily due to changes in state apportionment rates following the reorganization of Southern Power's legal entities that own and operate certain solar facilities and a reduction of tax benefits from wind PTCs primarily as a result of the sale of a noncontrolling tax equity interest in SP Wind.
Southern Company Gas
Southern Company Gas' effective tax rate was 22.3% for the three months ended March 31, 2019 compared to 27.2% for the corresponding period in 2018. This decrease was primarily related to tax impacts of the goodwill impairment charge recorded in the first quarter 2018 and an increase in the flowback of excess deferred income taxes in 2019 primarily at Atlanta Gas Light as previously authorized by the Georgia PSC. See Note 2 to the financial statements under "Southern Company Gas – Rate Proceedings" 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

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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.
Components of the net periodic benefit costs for the three months ended March 31, 2019 and 2018 are presented in the following tables.
Three Months Ended
March 31, 2019
Southern
Company
 
Alabama
Power
 
Georgia
Power
 
Mississippi
Power
 Southern Power Southern Company Gas
 (in millions)
Pension Plans
Service cost$73
 $17
 $19
 $3
 $2
 $6
Interest cost123
 28
 39
 6
 1
 9
Expected return on plan assets(221) (51) (73) (10) (2) (15)
Amortization:           
Prior service costs
 
 
 
 
 (1)
Regulatory asset
 
 
 
 
 3
Net (gain)/loss30
 9
 11
 1
 
 1
Net periodic pension cost (income)$5
 $3
 $(4) $
 $1
 $3
Postretirement Benefits
Service cost$5
 $1
 $1
 $
 $
 $1
Interest cost17
 4
 7
 1
 
 2
Expected return on plan assets(16) (6) (6) 
 
 (2)
Amortization:           
Prior service costs1
 1
 
 
 
 
Regulatory asset
 
 
 
 
 2
Net (gain)/loss(1) 
 
 
 
 (1)
Net periodic postretirement benefit cost$6
 $
 $2
 $1
 $
 $2

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Three Months Ended
March 31, 2018
Southern
Company
 
Alabama
Power
 
Georgia
Power
 
Mississippi
Power
 Southern Power Southern Company Gas
 (in millions)
Pension Plans
Service cost$90

$19

$22

$4

$2

$8
Interest cost116

25

35

5

1

10
Expected return on plan assets(236)
(51)
(74)
(10)
(3)
(18)
Amortization:           
Prior service costs1









(1)
Regulatory asset
 
 
 
 
 3
Net (gain)/loss53

14

17

3

1

3
Net periodic pension cost (income)$24

$7

$

$2

$1

$5
Postretirement Benefits
Service cost$6
 $1
 $2
 $
 $
 $1
Interest cost19
 4
 7
 1
 
 2
Expected return on plan assets(17) (6) (6) 
 
 (2)
Amortization:           
Prior service costs2
 1
 
 
 
 
Regulatory asset
 
 
 
 
 1
Net (gain)/loss3
 
 2
 
 
 
Net periodic postretirement benefit cost$13
 $
 $5
 $1
 $
 $2

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(I) FAIR VALUE MEASUREMENTS
As of June 30, 2018,March 31, 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:  Fair Value Measurements Using:  
As of June 30, 2018:
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 Net Asset Value as a Practical Expedient (NAV) Total
As of March 31, 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)(in millions)
Southern Company                  
Assets:                  
Energy-related derivatives(a)(b)
$287
 $166
 $
 $
 $453
$322
 $128
 $4
 $
 $454
Foreign currency derivatives
 132
 
 
 132

 38
 
 
 38
Nuclear decommissioning trusts(c)
798
 998
 
 33
 1,829
Investments in trusts:(c)(d)
         
Domestic equity682
 120
 
 
 802
Foreign equity60
 195
 
 
 255
U.S. Treasury and government agency securities
 283
 
 
 283
Municipal bonds
 73
 
 
 73
Pooled funds – fixed income
 14
 
 
 14
Corporate bonds24
 298
 
 
 322
Mortgage and asset backed securities
 72
 
 
 72
Private equity
 
 
 48
 48
Cash and cash equivalents1
 
 
 
 1
Other28
 4
 
 
 32
Cash equivalents1,449
 
 
 
 1,449
907
 3
 
 
 910
Other investments9
 
 1
 
 10
9
 14
 
 
 23
Total$2,543
 $1,296
 $1
 $33
 $3,873
$2,033
 $1,242
 $4
 $48
 $3,327
Liabilities:                  
Energy-related derivatives(a)(b)
$422
 $151
 $
 $
 $573
$466
 $106
 $23
 $
 $595
Interest rate derivatives
 68
 
 
 68

 35
 
 
 35
Foreign currency derivatives
 23
 
 
 23

 24
 
 
 24
Contingent consideration
 
 22
 
 22

 
 21
 
 21
Total$422
 $242
 $22
 $
 $686
$466
 $165
 $44
 $
 $675
                  
Alabama Power         
Assets:         
Energy-related derivatives$
 $8
 $
 $
 $8
Nuclear decommissioning trusts:(d)
        

Domestic equity440
 86
 
 
 526
Foreign equity61
 55
 
 
 116
U.S. Treasury and government agency securities
 18
 
 
 18
Corporate bonds28
 158
 
 
 186
Mortgage and asset backed securities
 18
 
 
 18
Private equity
 
 
 33
 33
Other7
 
 
 
 7
Cash equivalents495
 
 
 
 495
Total$1,031
 $343
 $
 $33
 $1,407
Liabilities:         
Energy-related derivatives$
 $9
 $
 $
 $9

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(UNAUDITED)

Fair Value Measurements Using:  Fair Value Measurements Using:  
As of June 30, 2018:
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 Net Asset Value as a Practical Expedient (NAV) Total
As of March 31, 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:(c)
        

Domestic equity446
 108
 
 
 554
Foreign equity60
 57
 
 
 117
U.S. Treasury and government agency securities
 18
 
 
 18
Municipal bonds
 1
 
 
 1
Corporate bonds24
 139
 
 
 163
Mortgage and asset backed securities
 24
 
 
 24
Private equity
 
 
 48
 48
Other5
 
 
 
 5
Cash equivalents569
 3
 
 
 572
Other investments
 14
 
 
 14
Total$1,104
 $370
 $
 $48
 $1,522
Liabilities:         
Energy-related derivatives$
 $7
 $
 $
 $7
(in millions)         
Georgia Power                  
Assets:                  
Energy-related derivatives$
 $7
 $
 $
 $7
$
 $9
 $
 $
 $9
Nuclear decommissioning trusts:(d) (e)
         
Nuclear decommissioning trusts:(c)(d)
         
Domestic equity242
 1
 
 
 243
236
 1
 
 
 237
Foreign equity
 135
 
 
 135

 134
 
 
 134
U.S. Treasury and government agency securities
 239
 
 
 239

 265
 
 
 265
Municipal bonds
 78
 
 
 78

 72
 
 
 72
Corporate bonds
 164
 
 
 164

 160
 
 
 160
Mortgage and asset backed securities
 41
 
 
 41

 47
 
 
 47
Other19
 5
 
 
 24
23
 4
 
 
 27
Total$261
 $670
 $
 $
 $931
$259
 $692
 $
 $
 $951
Liabilities:                  
Energy-related derivatives$
 $19
 $
 $
 $19
$
 $16
 $
 $
 $16
Interest rate derivatives
 6
 
 
 6

 2
 
 
 2
Total$
 $25
 $
 $
 $25
$
 $18
 $
 $
 $18
                  
Gulf Power         
Assets:         
Cash equivalents$27
 $
 $
 $
 $27
Liabilities:         
Energy-related derivatives$
 $12
 $
 $
 $12
         
Mississippi Power         
Assets:         
Energy-related derivatives$
 $3
 $
 $
 $3
Cash equivalents205
 
 
 
 205
Total$205
 $3
 $
 $
 $208
Liabilities:         
Energy-related derivatives$
 $9
 $
 $
 $9
         

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

Fair Value Measurements Using:  Fair Value Measurements Using:  
As of June 30, 2018:
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 Net Asset Value as a Practical Expedient (NAV) Total
As of March 31, 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 equivalents202
 
 
 
 202
Total$202
 $3
 $
 $
 $205
Liabilities:         
Energy-related derivatives$
 $6
 $
 $
 $6
(in millions)         
Southern Power                  
Assets:                  
Energy-related derivatives$
 $3
 $
 $
 $3
$
 $1
 $
 $
 $1
Foreign currency derivatives
 132
 
 
 132

 38
 
 

38
Cash equivalents10
 
 
 
 10
Total$
 $135
 $
 $
 $135
$10
 $39
 $
 $
 $49
Liabilities:                  
Energy-related derivatives$
 $3
 $
 $
 $3
$
 $3
 $
 $
 $3
Foreign currency derivatives
 23
 
 
 23

 24
 
 
 24
Contingent consideration
 
 22
 
 22

 
 21
 
 21
Total$

$26

$22

$

$48
$

$27

$21

$

$48
                  
Southern Company Gas                  
Assets:                  
Energy-related derivatives(a)(b)
$287
 $144
 $
 $
 $431
$322
 $108
 $4
 $
 $434
Non-qualified deferred compensation trusts:         
Domestic equity
 11
 
 
 11
Foreign equity
 4
 
 
 4
Pooled funds – fixed income
 14
 
 
 14
Cash equivalents1
 
 
 
 1
Cash equivalents1
 
 
 
 1
13
 
 
 
 13
Total$288

$144

$

$

$432
$336

$137

$4

$

$477
Liabilities:                  
Energy-related derivatives(a)(b)
$422
 $99
 $
 $
 $521
$466
 $73
 $23
 $
 $562
(a)Excludes $3
Energy-related derivatives exclude $11 million associated with premiums and certain weather derivatives accounted for based on intrinsic value rather than fair value.
(b)Excludes
Energy-related derivatives exclude cash collateral of $183 million.$190 million.
(c)For additional detail, see the nuclear decommissioning trusts sections for Alabama Power and Georgia Power in this table.
(d)Excludes receivables related to investment income, pending investment sales, payables related to pending investment purchases, and currencies. See Note 6 to the financial statements in Item 8 of the Form 10-K for additional information.
(e)(d)
Includes the investment securities pledged to creditors and collateral received and excludes payables related to the securities lending program. As of June 30, 2018,March 31, 2019, approximately $63$72 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.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

Southern Company, Alabama Power, and Georgia Power continue to elect the option to fair value investment securities held in the nuclear decommissioning trust funds. The fair value of the funds, at Southern Company, including reinvested interest and dividends and excluding the funds' expenses, increased by $14 million and $4 million, respectively, for the three and six months ended June 30, 2018March 31, 2019 and increased by $55 million and $118 million, respectively,decreased for the three and six months ended June 30, 2017. Alabama PowerMarch 31, 2018 by the amounts shown in the table below. The changes were recorded an increase in fair value of $15 million and $10 million, respectively, for the three and six months ended June 30, 2018 and an increase of $28 million and $62 million, respectively, for the three and six months ended June 30, 2017 as a change into the regulatory assets and liabilities related to its AROs.AROs for Georgia Power recorded a decrease in fair value of $1 million and $6 million, respectively, for the three and six months ended June 30, 2018 and an increase of $27 million and $56 million, respectively, for the three and six months ended June 30, 2017 as a change in its regulatory asset related to its AROs.Alabama Power, respectively.

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

 
Three Months Ended
March 31, 2019
Three Months
Ended
March 31, 2018
 (in millions)
Southern Company$152
$(11)
Alabama Power87
(5)
Georgia Power65
(6)
Valuation MethodologiesDOE Loan Guarantee Borrowings
The energy-related derivatives primarily consist of exchange-traded and over-the-counter financial products for natural gas and physical power products, including, from time to time, basis swaps. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices, power prices, implied volatility, and overnight index swap interest rates. Interest rate derivatives are also standard over-the-counter products that are valued using observable market data and assumptions commonly used by market participants. The fair value of interest rate derivatives reflects the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future interest rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk, and occasionally, implied volatility of interest rate options. The fair value of cross-currency swaps reflects the net present value of expected payments and receipts under the swap agreement based on the market's expectation of future foreign currency exchange rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk, and discount rates. The interest rate derivatives and cross-currency swaps are categorized as Level 2 under Fair Value Measurements as these inputs are based on observable data and valuations of similar instruments. See Note (I) for additional information on how these derivatives are used.
The NRC requires licensees of commissioned nuclear power reactors to establish a plan for providing reasonable assurance of funds for future decommissioning. For fair value measurements of the investments within the nuclear decommissioning trusts, external pricing vendors are designated for each asset class with each security specifically assigned a primary pricing source. For investments held within commingled funds, fair value is determined at the end of each business day through the net asset value, which is established by obtaining the underlying securities' individual prices from the primary pricing source. A market price secured from the primary source vendor is then evaluated by management in its valuation of the assets within the trusts. As a general approach, fixed income market pricing vendors gather market data (including indices and market research reports) and integrate relative credit information, observed market movements, and sector news into proprietary pricing models, pricing systems, and mathematical tools. Dealer quotes and other market information, including live trading levels and pricing analysts' judgments, are also obtained when available. See Note 18 to the financial statements of Southern Company, Alabama Power, and Georgia Power under "Nuclear Decommissioning""Long-term Debt – DOE Loan Guarantee Borrowings" in Item 8 of the Form 10-K for additional information.information regarding Georgia Power's 2014 loan guarantee agreement.
Southern Power has contingent payment obligations related to certain acquisitions whereby Southern Power is primarily obligated to make generation-based paymentsPursuant to the seller,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 commencedprovide 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).
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 commercial operationfinal maturity date of February 20, 2044. At March 31, 2019, Georgia Power had a total of $3.46 billion of borrowings outstanding under 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.FFB Credit Facilities.
"Other investments" include investments that are not traded in the open market. The fair value of these investments has been determined based on market factors including comparable multiples and the expectations regarding cash flows and business plan executions.
As of June 30, 2018, the fair value measurements of private equity investments held in the nuclear decommissioning trusts that are calculated at net asset value per share (or its equivalent) as a practical expedient, as well as the nature and risks of those investments, were as follows:
163

As of June 30, 2018:
Fair
Value
 
Unfunded
Commitments
 
Redemption
Frequency
 
Redemption
Notice Period
 (in millions)    
Southern Company$33
 $33
 Not Applicable Not Applicable
Alabama Power$33
 $33
 Not Applicable Not Applicable
Table of Contents

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

Private equity funds includeAll 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 fund-of-fundsfirst 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 invests in high-quality private equity funds across several market sectors, funds that invest in real estate assets,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 fund that acquires companiesspread equal to create resale value. Private equity funds do not have redemption rights. Distributions from these funds0.375%.
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.
In connection with any cancellation of Plant Vogtle Units 3 and 4, the underlying investmentsDOE 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.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

Financing Activities
The following table outlines the funds are liquidated. Liquidations are expected to occur at various times overlong-term debt financing activities for Southern Company and its subsidiaries for the next 10 years.
Asfirst three months of June 30, 2018, other financial instruments for which the carrying amount did not equal fair value were as follows:2019:
 
Carrying
Amount
 
Fair
Value
 (in millions)
Long-term debt, including securities due within one year:   
Southern Company$45,806
 $46,481
Alabama Power8,119
 8,435
Georgia Power10,294
 10,499
Gulf Power1,285
 1,311
Mississippi Power1,779
 1,760
Southern Power5,037
 5,094
Southern Company Gas5,823
 5,957
The fair values are determined using Level 2 measurements and are based on quoted market prices for the same or similar issues or on the current rates available to Southern Company, Alabama Power, Georgia Power, Gulf Power, Mississippi Power, Southern Power, and Southern Company Gas.
CompanySenior 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 Power200
 
 
 
 
Georgia Power
 343
 108
 835
 2
Mississippi Power
 43
 
 
 
Other
 
 
 
 19
Southern Company Consolidated$2,300
 $386
 $108
 $835
 $21
(E)(a)STOCKHOLDERS' EQUITYIncludes 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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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(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.
Subsequent to March 31, 2019, Georgia Power purchased and held the following pollution control revenue bonds, which may be reoffered to the public at a later date:
$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.
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, that previously had been purchased and held by Mississippi Power.
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 812 to the financial statements of Southern Company in Item 8 of the Form 10-K for information on stock-based compensation plans. The effect of stock-based compensation plans was determined using the treasury stock method. Shares used to compute diluted earnings per share were as follows:
Three Months Ended
June 30, 2018
Three Months Ended
June 30, 2017
Six Months Ended
June 30, 2018
Six Months Ended
June 30, 2017
Three Months Ended March 31, 2019Three Months Ended March 31, 2018
(in millions)(in millions)
As reported shares1,014
998
1,012
996
1,038
1,011
Effect of stock-based compensation
7
5
7
7
5
Diluted shares1,014
1,005
1,017
1,003
1,045
1,016
Stock-basedThere were no stock-based compensation awards that were not included in the diluted earnings per share calculation because they were anti-dilutive totaled approximately 5.3 million shares for the three months ended June 30, 2018March 31, 2019 and werean immaterial amount of such awards was not included for the three months ended June 30, 2017 and six months ended June 30, 2018 and 2017.March 31, 2018.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

Changes(G) INCOME TAXES
See Note 10 to the financial statements in Stockholders' EquityItem 8 of the Form 10-K for additional tax information.
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 39.8% for the three months ended March 31, 2019 compared to 10.8% for the corresponding period in 2018. The effective tax rate increase was primarily due to the tax impact from the sale of Gulf Power. See Note (K) for additional information.
Alabama Power
Alabama Power's effective tax rate was 21.9% for the three months ended March 31, 2019 compared to 26.3% for the corresponding period in 2018. The effective tax rate decrease was primarily due to the application in 2018 of the accounting order approved by the Alabama PSC in May 2018 related to the Tax Reform Legislation. 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.
Mississippi Power
Mississippi Power's effective tax rate was 15.5% for the three months ended March 31, 2019 compared to a benefit rate of (34.7)% for the corresponding period in 2018. The effective tax rate increase was primarily due to lower estimated losses on the Kemper IGCC in 2019, partially offset by 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.
Southern Power
Southern Power's effective tax benefit rate was (49.8)% for the three months ended March 31, 2019 compared to (647.0)% for the corresponding period in 2018. The effective tax benefit rate decrease was primarily due to changes in state apportionment rates following the reorganization of Southern Power's legal entities that own and operate certain solar facilities and a reduction of tax benefits from wind PTCs primarily as a result of the sale of a noncontrolling tax equity interest in SP Wind.
Southern Company Gas
Southern Company Gas' effective tax rate was 22.3% for the three months ended March 31, 2019 compared to 27.2% for the corresponding period in 2018. This decrease was primarily related to tax impacts of the goodwill impairment charge recorded in the first quarter 2018 and an increase in the flowback of excess deferred income taxes in 2019 primarily at Atlanta Gas Light as previously authorized by the Georgia PSC. See Note 2 to the financial statements under "Southern Company Gas – Rate Proceedings" 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

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

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.
Components of the net periodic benefit costs for the three months ended March 31, 2019 and 2018 are presented in the following table presents year-to-date changes in stockholders' equity of Southern Company:tables.
 
Number of
Common Shares
 Common
Stockholders'
Equity
Preferred and
Preference
Stock of
Subsidiaries
 Total
Stockholders'
Equity
 IssuedTreasury 
Noncontrolling Interests(a)
 (in thousands) (in millions)
Balance at December 31, 20171,008,532
(929) $24,167
$
$1,361
$25,528
Consolidated net income attributable to Southern Company

 784


784
Other comprehensive income

 41


41
Stock issued6,590

 222


222
Stock-based compensation

 48


48
Cash dividends on common stock

 (1,194)

(1,194)
Contributions from noncontrolling interests

 

31
31
Distributions to noncontrolling interests

 

(42)(42)
Net income attributable to noncontrolling interests

 

17
17
Sale of SPSH noncontrolling interests(b)


 (407)
1,690
1,283
Other
(57) (25)
(1)(26)
Balance at June 30, 20181,015,122
(986) $23,636
$
$3,056
$26,692
        
Balance at December 31, 2016991,213
(819) $24,758
$609
$1,245
$26,612
Consolidated net income attributable to Southern Company

 (723)

(723)
Other comprehensive income (loss)

 (11)

(11)
Stock issued9,129

 417


417
Stock-based compensation

 72


72
Cash dividends on common stock

 (1,134)

(1,134)
Preference stock redemption

 
(150)
(150)
Contributions from noncontrolling interests

 

71
71
Distributions to noncontrolling interests

 

(40)(40)
Net income attributable to noncontrolling interests

 

16
16
Reclassification from redeemable noncontrolling interests

 

114
114
Other
(49) (7)3
1
(3)
Balance at June 30, 20171,000,342
(868) $23,372
$462
$1,407
$25,241
Three Months Ended
March 31, 2019
Southern
Company
 
Alabama
Power
 
Georgia
Power
 
Mississippi
Power
 Southern Power Southern Company Gas
 (in millions)
Pension Plans
Service cost$73
 $17
 $19
 $3
 $2
 $6
Interest cost123
 28
 39
 6
 1
 9
Expected return on plan assets(221) (51) (73) (10) (2) (15)
Amortization:           
Prior service costs
 
 
 
 
 (1)
Regulatory asset
 
 
 
 
 3
Net (gain)/loss30
 9
 11
 1
 
 1
Net periodic pension cost (income)$5
 $3
 $(4) $
 $1
 $3
Postretirement Benefits
Service cost$5
 $1
 $1
 $
 $
 $1
Interest cost17
 4
 7
 1
 
 2
Expected return on plan assets(16) (6) (6) 
 
 (2)
Amortization:           
Prior service costs1
 1
 
 
 
 
Regulatory asset
 
 
 
 
 2
Net (gain)/loss(1) 
 
 
 
 (1)
Net periodic postretirement benefit cost$6
 $
 $2
 $1
 $
 $2

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

Three Months Ended
March 31, 2018
Southern
Company
 
Alabama
Power
 
Georgia
Power
 
Mississippi
Power
 Southern Power Southern Company Gas
 (in millions)
Pension Plans
Service cost$90

$19

$22

$4

$2

$8
Interest cost116

25

35

5

1

10
Expected return on plan assets(236)
(51)
(74)
(10)
(3)
(18)
Amortization:           
Prior service costs1









(1)
Regulatory asset
 
 
 
 
 3
Net (gain)/loss53

14

17

3

1

3
Net periodic pension cost (income)$24

$7

$

$2

$1

$5
Postretirement Benefits
Service cost$6
 $1
 $2
 $
 $
 $1
Interest cost19
 4
 7
 1
 
 2
Expected return on plan assets(17) (6) (6) 
 
 (2)
Amortization:           
Prior service costs2
 1
 
 
 
 
Regulatory asset
 
 
 
 
 1
Net (gain)/loss3
 
 2
 
 
 
Net periodic postretirement benefit cost$13
 $
 $5
 $1
 $
 $2

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

(I) FAIR VALUE MEASUREMENTS
As of March 31, 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 March 31, 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)(b)
$322
 $128
 $4
 $
 $454
Foreign currency derivatives
 38
 
 
 38
Investments in trusts:(c)(d)
         
Domestic equity682
 120
 
 
 802
Foreign equity60
 195
 
 
 255
U.S. Treasury and government agency securities
 283
 
 
 283
Municipal bonds
 73
 
 
 73
Pooled funds – fixed income
 14
 
 
 14
Corporate bonds24
 298
 
 
 322
Mortgage and asset backed securities
 72
 
 
 72
Private equity
 
 
 48
 48
Cash and cash equivalents1
 
 
 
 1
Other28
 4
 
 
 32
Cash equivalents907
 3
 
 
 910
Other investments9
 14
 
 
 23
Total$2,033
 $1,242
 $4
 $48
 $3,327
Liabilities:         
Energy-related derivatives(a)(b)
$466
 $106
 $23
 $
 $595
Interest rate derivatives
 35
 
 
 35
Foreign currency derivatives
 24
 
 
 24
Contingent consideration
 
 21
 
 21
Total$466
 $165
 $44
 $
 $675
          

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

 Fair Value Measurements Using:  
As of March 31, 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:(c)
        

Domestic equity446
 108
 
 
 554
Foreign equity60
 57
 
 
 117
U.S. Treasury and government agency securities
 18
 
 
 18
Municipal bonds
 1
 
 
 1
Corporate bonds24
 139
 
 
 163
Mortgage and asset backed securities
 24
 
 
 24
Private equity
 
 
 48
 48
Other5
 
 
 
 5
Cash equivalents569
 3
 
 
 572
Other investments
 14
 
 
 14
Total$1,104
 $370
 $
 $48
 $1,522
Liabilities:         
Energy-related derivatives$
 $7
 $
 $
 $7
          
Georgia Power         
Assets:         
Energy-related derivatives$
 $9
 $
 $
 $9
Nuclear decommissioning trusts:(c)(d)
         
Domestic equity236
 1
 
 
 237
Foreign equity
 134
 
 
 134
U.S. Treasury and government agency securities
 265
 
 
 265
Municipal bonds
 72
 
 
 72
Corporate bonds
 160
 
 
 160
Mortgage and asset backed securities
 47
 
 
 47
Other23
 4
 
 
 27
Total$259
 $692
 $
 $
 $951
Liabilities:         
Energy-related derivatives$
 $16
 $
 $
 $16
Interest rate derivatives
 2
 
 
 2
Total$
 $18
 $
 $
 $18
          

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

 Fair Value Measurements Using:  
As of March 31, 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 equivalents202
 
 
 
 202
Total$202
 $3
 $
 $
 $205
Liabilities:         
Energy-related derivatives$
 $6
 $
 $
 $6
          
Southern Power         
Assets:         
Energy-related derivatives$
 $1
 $
 $
 $1
Foreign currency derivatives
 38
 
 

38
Cash equivalents10
 
 
 
 10
Total$10
 $39
 $
 $
 $49
Liabilities:         
Energy-related derivatives$
 $3
 $
 $
 $3
Foreign currency derivatives
 24
 
 
 24
Contingent consideration
 
 21
 
 21
Total$

$27

$21

$

$48
          
Southern Company Gas         
Assets:         
Energy-related derivatives(a)(b)
$322
 $108
 $4
 $
 $434
Non-qualified deferred compensation trusts:         
Domestic equity
 11
 
 
 11
Foreign equity
 4
 
 
 4
Pooled funds – fixed income
 14
 
 
 14
Cash equivalents1
 
 
 
 1
Cash equivalents13
 
 
 
 13
Total$336

$137

$4

$

$477
Liabilities:         
Energy-related derivatives(a)(b)
$466
 $73
 $23
 $
 $562
(a)Primarily
Energy-related derivatives exclude $11 million associated with premiums and certain weather derivatives accounted for based on intrinsic value rather than fair value.
(b)
Energy-related derivatives exclude cash collateral of $190 million.
(c)Excludes receivables related to Southern Power Companyinvestment income, pending investment sales, payables related to pending investment purchases, and excludes redeemable noncontrolling interests.currencies. See Note 106 to the financial statements of Southern Power in Item 8 of the Form 10-K for additional information.
(b)(d)
Includes investment securities pledged to creditors and collateral received and excludes payables related to the securities lending program. As of March 31, 2019, approximately $72 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 (J) under "Southern Power – Sale6 to the financial statements in Item 8 of Solar Facility Interests"the Form 10-K for additional information.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

(F)FINANCING
Bank Credit Arrangements
Bank credit arrangements provide liquidity supportSouthern 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 and dividends and excluding the funds' expenses, increased for the three months ended March 31, 2019 and decreased for the three months ended March 31, 2018 by the amounts shown in the table below. The changes were recorded as a change to the registrants' commercial paper borrowingsregulatory assets and the traditional electric operating companies' revenue bonds. The amount of variable rate revenue bonds of the traditional electric operating companies outstanding requiring liquidity support as of June 30, 2018 was approximately $1.5 billion (comprised of approximately $854 million atliabilities related to AROs for Georgia Power and Alabama Power, $550 million at Georgia Power, $82 million at Gulf Power, and $40 million at Mississippi Power). In addition, at June 30, 2018, the traditional electric operating companies had approximately $482 million (comprised of approximately $120 million at Alabama Power, $232 million at Georgia Power, $37 million at Gulf Power, and $93 million at Mississippi Power) of revenue bonds outstanding that were required to be remarketed within the next 12 months. Subsequent to June 30, 2018, approximately $43 million of these pollution control revenue bonds of Mississippi Power were purchased and held by Mississippi Power. See Note 6 to the financial statements of each registrant under "Bank Credit Arrangements" in Item 8 of the Form 10-K and "Financing Activities" herein for additional information.
The following table outlines the committed credit arrangements by company as of June 30, 2018:respectively.
 Expires   
Executable Term
Loans
 
Expires Within
One Year
Company2018201920202022 Total Unused 
One
Year
 
Term
Out
 
No Term
Out
 (in millions)
Southern Company(a)
$
$
$
$2,000
 $2,000
 $1,999
 $
 $
 $
Alabama Power2
31
500
800
 1,333
 1,333
 
 
 33
Georgia Power


1,750
 1,750
 1,736
 
 
 
Gulf Power20
25
235

 280
 280
 45
 45
 
Mississippi Power100



 100
 100
 
 
 100
Southern Power Company(b)



750
 750
 728
 
 
 
Southern Company Gas(c)



1,900
 1,900
 1,895
 
 
 
Other
30


 30
 30
 
 
 30
Southern Company Consolidated$122
$86
$735
$7,200
 $8,143
 $8,101
 $45
 $45
 $163
 
Three Months Ended
March 31, 2019
Three Months
Ended
March 31, 2018
 (in millions)
Southern Company$152
$(11)
Alabama Power87
(5)
Georgia Power65
(6)
(a)Represents the Southern Company parent entity.
(b)
Does not include Southern Power's $120 million continuing letter of credit facility for standby letters of credit expiring in 2019, of which $23 million remains unused at June 30, 2018.
(c)
Southern Company Gas, as the parent entity, guarantees the obligations of Southern Company Gas Capital, which is the borrower of $1.4 billion of these arrangements. Southern Company Gas' committed credit arrangements also include $500 million for which Nicor Gas is the borrower and which is restricted for working capital needs of Nicor Gas.
Subject to applicable market conditions, Southern Company and its subsidiaries expect to renew or replace their bank credit arrangements as needed, prior to expiration. In connection therewith, Southern Company and its subsidiaries may extend the maturity dates and/or increase or decrease the lending commitments thereunder.
DOE Loan Guarantee Borrowings
See Note 68 to the financial statements of Southern Company and Georgia Power under "DOE"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 Agreement.
On July 27, 2017,Program), Georgia Power and the DOE entered into an amendment toa loan guarantee agreement in 2014 and the Amended and Restated Loan Guarantee Agreement (LGA Amendment) in connection withMarch 2019. Under the DOE's consentAmended and Restated Loan Guarantee Agreement, the DOE has agreed to guarantee the obligations of Georgia Power's entry intoPower under note purchase agreements among the Vogtle Services AgreementDOE, Georgia Power, and the FFB and related intellectual property licenses (IP Licenses)promissory notes which provide for two multi-advance term loan facilities (FFB Credit Facilities). Under the termsFFB 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 Loanamounts received by Georgia Power under the Guarantee Settlement Agreement upon terminationless 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 March 31, 2019, Georgia Power had a total of $3.46 billion of borrowings outstanding under the FFB Credit Facilities.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

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 Agreement, further advances are conditioned upon(primarily the DOE's approval ofunits under construction, the related real property, and any agreements entered intonuclear fuel loaded in replacement of the Vogtle 3 and 4 Agreement. Under the terms of the LGA Amendment, Georgia Power will not request any advances unless and until certain conditions are satisfied, including (i) receipt of the DOE's approval of the Bechtel Agreement (together with the Vogtle Services Agreement and the IP Licenses, the Replacement EPC Arrangements)reactor core) and (ii) Georgia Power's entry into a further amendmentrights 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 Loan Guarantee Agreement with the DOE to reflect the Replacement EPC Arrangements.
In September 2017, the DOE issued a conditional commitment to Georgia Power for up to approximately $1.67 billion in additional guaranteed loans under the Loan Guarantee Agreement. In June 2018, the DOE approved a request by Georgia Power to extend the conditional commitment to September 30, 2018. Any further extension must be approved by the DOE. Final approval and issuance of these additional loan guarantees by the DOE cannot be assured andconditions described above, future advances are subject to the negotiation of definitive agreements, completion of due diligence by the DOE, receipt of any necessary regulatory approvals, and satisfaction of othercustomary 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 Vogtle Owners' votesprevailing 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 continue construction.reimburse Eligible Project Costs.
AsUpon satisfaction of June 30, 2018, Georgia Power had $2.6 billion of borrowings outstandingall conditions described above, advances may be requested on a quarterly basis through 2023. The final maturity date for each advance under the multi-advance term loan facility (FFBFFB Credit Facility) among Georgia Power,Facilities is February 20, 2044. Interest is payable quarterly and principal payments will begin on February 20, 2020. Borrowings under the DOE, andFFB Credit Facilities will bear interest at the FFB.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 (including any decision not to continue construction of Plant Vogtle Units 3 and 4) occur, the FFB's commitment to make further advances under the FFB Credit FacilityFacilities will terminate and Georgia Power will be required to prepay the outstanding principal amount of all borrowings under the FFB Credit FacilityFacilities 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 IP Licenses;related intellectual property licenses; (ii) termination of the Bechtel Agreement, unless the Vogtle Owners enter into a decision by Georgia Power not to continue construction of Plant Vogtle Units 3 and 4;replacement agreement; (iii) cancellation of Plant Vogtle Units 3 and 4 by the Georgia PSC or by Georgia Power if authorized byPower; (iv) failure of the Georgia PSC;holders of 90% of the ownership interests in Plant Vogtle Units 3 and (iv)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 Facility.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 Facility.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 FacilityFacilities 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.Agreement less the Customer Refunds. Georgia Power also may voluntarily prepay outstanding borrowings under the FFB Credit Facility.Facilities. Under the FFB Credit Facility,Facilities, any prepayment (whether mandatory or optional) will be made with a make-whole premium or discount, as applicable.
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.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

Financing Activities
The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first sixthree months of 2018:2019:
Company
Senior
Note
Issuances
 Senior Note Maturities, Redemptions, and Repurchases Revenue Bond
Maturities, Redemptions, and
Repurchases
 
Other Long-Term Debt Redemptions
and Maturities(*)
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)(in millions)
Southern Company(b)
$2,100
 $
 $
 $
 $
Alabama Power$500
 $
 $
 $
200
 
 
 
 
Georgia Power
 1,000
 398
 104

 343
 108
 835
 2
Mississippi Power600
 
 
 900

 43
 
 
 
Southern Power
 350
 
 420
Southern Company Gas
 
 200
 
Other
 
 
 7

 
 
 
 19
Southern Company Consolidated$1,100
 $1,350
 $598
 $1,431
$2,300
 $386
 $108
 $835
 $21
(*)(a)Includes reductions in capitalfinance lease obligations resulting from cash payments under capitalfinance leases.
(b)Represents the Southern Company parent entity.
Southern Company
In March 2018, Southern Company entered into a $900 million short-term floating rate bank loan bearing interest based on one-month LIBOR. The proceeds were used for working capital and other general corporate purposes.
In April 2018, Southern Company borrowed $250 million pursuant to a short-term uncommitted bank credit arrangement, which bears interest at a rate agreed upon byExcept as otherwise described herein, Southern Company and its subsidiaries used the bank from time to timeproceeds of debt issuances for their redemptions and is payable on no less than 30 days' demand bymaturities shown in the bank.
In June 2018, Southern Company repaid at maturity two $100 million short-term floating rate bank term loans.
Alabama Power
In June 2018, Alabama Power issued $500 million aggregate principal amount of Series 2018A 4.30% Senior Notes due July 15, 2048. The proceeds were usedtable above, to repay outstanding commercial papershort-term indebtedness, and for general corporate purposes, including Alabama Power's continuousworking capital. The subsidiaries also used the proceeds for their construction program.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 2018,2019, Georgia Power repaid its outstanding $150redeemed approximately $13 million, $20 million, and $100 million floating rate bank loans due May 31, 2018 and October 26, 2018, respectively.
In March 2018, Georgia Power purchased and held $104.6$75 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 20131992, Eighth Series 1994, and $173Second Series 1995, respectively.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(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. Georgia Power may reoffer these bonds to the public at a later date.2009;
In April 2018, Georgia Power purchased and held $55approximately $105 million aggregate principal amount of Development Authority of Burke County (Georgia) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), FifthFirst Series 1994. Georgia Power may reoffer these bonds to the public at a later date.2013; and
Also in April 2018, Georgia Power redeemed all $250 million aggregate principal amount of its Series 2008B 5.40% Senior Notes due June 1, 2018.

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

In May 2018, through cash tender offers, Georgia Power repurchased and retired $89 million of the $250 million aggregate principal amount outstanding of its Series 2007A 5.65% Senior Notes due March 1, 2037, $326 million of the $500 million aggregate principal amount outstanding of its Series 2009A 5.95% Senior Notes due February 1, 2039, and $335 million of the $600 million aggregate principal amount outstanding of its Series 2010B 5.40% Senior Notes due June 1, 2040, for an aggregate purchase price, excluding accrued and unpaid interest, of $902 million.
In June 2018, Georgia Power purchased and held $65$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.
Subsequent to March 31, 2019, Georgia Power purchased and held the following pollution control revenue bonds, which may reoffer these bondsbe reoffered to the public at a later date.date:
$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.
Mississippi Power
In March 2018,2019, Mississippi Power issued $300reoffered to the public $43 million aggregate principalof Mississippi Business Finance Corporation Pollution Control Revenue Refunding Bonds, Series 2002, that previously had been purchased and held by Mississippi Power.
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 March 31, 2019Three Months Ended March 31, 2018
 (in millions)
As reported shares1,038
1,011
Effect of stock-based compensation7
5
Diluted shares1,045
1,016
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 months ended March 31, 2019 and an immaterial amount of Series 2018A Floating Rate Senior Notes duesuch awards was not included for the three months ended March 27, 2020 bearing interest based on three-month LIBOR and $300 million aggregate principal amount of Series 2018B 3.95% Senior Notes due March 30, 2028. In March 2018, Mississippi Power also entered into a $300 million short-term floating rate bank loan bearing interest based on one-month LIBOR, of which $200 million was repaid in the second quarter 2018 and $50 million was repaid subsequent to June 30,31, 2018. Mississippi Power used the proceeds from these financings to repay a $900 million unsecured term loan.
Southern Power
In May 2018, Southern Power entered into two short-term floating rate bank loans, each for an aggregate principal amount of $100 million, which bear interest based on one-month LIBOR.
166
In the second quarter 2018, Southern Power used a portion of the proceeds from the sale of a 33% equity interest in SPSH to repay $420 million aggregate principal amount of long-term floating rate bank loans and $350 million aggregate principal amount of Series 2015A 1.50% Senior Notes due June 1, 2018. See Note (J) under "Southern Power – Sale of Solar Facility Interests" for additional information.
Southern Company Gas
On January 4, 2018, Southern Company Gas issued a floating rate promissory note to Southern Company in an aggregate principal amount of $100 million bearing interest based on one-month LIBOR. On March 28, 2018, Southern Company Gas repaid this promissory note.
In the second quarter 2018, Pivotal Utility Holdings caused $200 million aggregate principal amount of gas facility revenue bonds to be redeemed. Also in the second quarter 2018, Pivotal Utility Holdings, as borrower, and Southern Company Gas, as guarantor, entered into a $181 million short-term delayed draw floating rate bank term loan bearing interest based on one-month LIBOR, which Pivotal Utility Holdings used to repay the gas facility revenue bonds. Subsequent to June 30, 2018, Pivotal Utility Holdings repaid this short-term loan.
In May 2018, Southern Company Gas Capital borrowed $95 million pursuant to a short-term uncommitted bank credit arrangement, guaranteed by Southern Company Gas, bearing interest at a rate agreed upon by Southern Company Gas Capital and the bank from time to time and payable on no less than 30 days' demand by the bank. The proceeds of the loan were used to pay down short-term debt. Subsequent to June 30, 2018, Southern Company Gas Capital repaid this loan.

(G)RETIREMENT BENEFITS
On January 1, 2018, the qualified defined benefit pension plan

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

contributions to the Southern Company qualified defined benefit pension plan are anticipated for the year ending December 31, 2018.
In addition, the Southern Company Gas non-qualified retirement plans were merged into the Southern Company non-qualified retirement plan (defined benefit and defined contribution). Following the non-qualified retirement plan mergers, Southern Company continues to provide certain non-qualified defined benefits for a select group of management and highly compensated employees, which are funded on a cash basis.
Furthermore, Southern Company provides certain medical care and life insurance benefits for retired employees through other postretirement benefit plans. The traditional electric operating companies fund related other postretirement trusts to the extent required by their respective regulatory commissions. Southern Company Gas also provides certain medical care and life insurance benefits for eligible retired employees through a postretirement benefit plan. Southern Company Gas has a separate unfunded supplemental retirement health care plan that provides medical care and life insurance benefits to employees of discontinued businesses.
As indicated in Note (A), the registrants adopted ASU 2017-07 as of January 1, 2018. ASU 2017-07 requires that an employer report the service cost component of net periodic benefit costs in the same line item or items as other compensation costs and requires the other components of net periodic benefit costs to be separately presented in the statements of income outside of income from operations. The presentation requirements of ASU 2017-07 have been applied retrospectively with the service cost component of net periodic benefit costs included in operations and maintenance and all other components of net periodic benefit costs included in other income (expense), net in the statements of income for the three and six months ended June 30, 2017.
With respect to the presentation requirements, the registrants have used the practical expedient provided by ASU 2017-07, which permits an employer to use the amounts disclosed in its retirement benefits footnote for prior comparative periods as the estimation basis for applying the retrospective presentation requirements to those periods. The amounts of the other components of net periodic benefit costs reclassified for the prior period are presented in the following tables.(G) INCOME TAXES
See Note 210 to the financial statements of each registrant in Item 8 of the Form 10-K for additional information.

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

Components of the net periodic benefit costs for the three and six months ended June 30, 2018 and 2017 are presented in the following tables.
Three Months Ended June 30, 2018
Southern
Company
 
Alabama
Power
 
Georgia
Power
 
Gulf
Power
 
Mississippi
Power
 Southern Power Southern Company Gas
 (in millions)
Pension Plans
Service cost$89
 $20
 $21
 $4
 $4
 $2
 $8
Interest cost116
 25
 35
 5
 5
 2
 9
Expected return on plan assets(235) (53) (74) (10) (10) (2) (17)
Amortization:             
Prior service costs1
 1
 1
 
 
 
 
Regulatory asset
 
 
 
 
 
 4
Net (gain)/loss54
 13
 17
 3
 2
 
 3
Net periodic pension cost (income)$25
 $6
 $
 $2
 $1
 $2
 $7
Postretirement Benefits
Service cost$6
 $2
 $1
 $1
 $1
 $
 $
Interest cost18
 4
 7
 
 1
 
 3
Expected return on plan assets(17) (7) (7) (1) (1) 
 (2)
Amortization:             
Prior service costs1
 1
 1
 
 
 
 
Regulatory asset
 
 
 
 
 
 2
Net (gain)/loss4
 1
 2
 
 
 
 
Net periodic postretirement benefit cost$12
 $1
 $4
 $
 $1
 $
 $3

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

Six Months Ended June 30, 2018
Southern
Company
 
Alabama
Power
 
Georgia
Power
 
Gulf
Power
 
Mississippi
Power
 Southern Power Southern Company Gas
 (in millions)
Pension Plans
Service cost$179
 $39
 $43
 $8
 $8
 $4
 $16
Interest cost232
 50
 70
 10
 10
 3
 19
Expected return on plan assets(471) (104) (148) (20) (20) (5) (35)
Amortization:             
Prior service costs2
 1
 1
 
 
 
 (1)
Regulatory asset
 
 
 
 
 
 7
Net (gain)/loss107
 27
 34
 5
 5
 1
 6
Net periodic pension cost (income)$49
 $13
 $
 $3
 $3
 $3
 $12
Postretirement Benefits
Service cost$12
 $3
 $3
 $1
 $1
 $
 $1
Interest cost37
 8
 14
 1
 2
 
 5
Expected return on plan assets(34) (13) (13) (1) (1) 
 (4)
Amortization:             
Regulatory asset3
 2
 1
 
 
 
 3
Net (gain)/loss7
 1
 4
 
 
 
 
Net periodic postretirement benefit cost$25
 $1
 $9
 $1
 $2
 $
 $5

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

Three Months Ended
June 30, 2017(*)
Southern
Company
 
Alabama
Power
 
Georgia
Power
 
Gulf
Power
 
Mississippi
Power
 Southern Company Gas
 (in millions)
Pension Plans
Service cost$74

$16

$18

$4

$3

$5
Interest cost113

24

35

5

5

10
Expected return on plan assets(225)
(49)
(70)
(9)
(10)
(17)
Amortization:           
Prior service costs3



1



1

(1)
Net (gain)/loss41

11

14

1

2

5
Net periodic pension cost (income)$6

$2

$(2)
$1

$1

$2
Postretirement Benefits
Service cost$6
 $2
 $1
 $1
 $1
 $
Interest cost20
 4
 8
 
 1
 2
Expected return on plan assets(17) (8) (6) (1) (1) (1)
Amortization:           
Prior service costs1
 1
 1
 
 
 
Net (gain)/loss5
 1
 1
 
 
 1
Net periodic postretirement benefit cost$15
 $
 $5
 $
 $1
 $2
(*)Excludes Southern Power since Southern Power did not participate in the qualified pension and postretirement benefit plans until December 2017.
Six Months Ended
June 30, 2017(*)
Southern
Company
 
Alabama
Power
 
Georgia
Power
 
Gulf
Power
 
Mississippi
Power
 Southern Company Gas
 (in millions)
Pension Plans
Service cost$147
 $32
 $37
 $7
 $7
 $11
Interest cost227
 48
 69
 10
 10
 20
Expected return on plan assets(449) (98) (141) (19) (20) (35)
Amortization:           
Prior service costs6
 1
 2
 
 1
 (1)
Net (gain)/loss81
 21
 28
 3
 4
 10
Net periodic pension cost (income)$12
 $4
 $(5) $1
 $2
 $5
Postretirement Benefits
Service cost$12
 $3
 $3
 $1
 $1
 $1
Interest cost40
 9
 15
 1
 2
 5
Expected return on plan assets(33) (14) (12) (1) (1) (3)
Amortization:           
Prior service costs3
 2
 1
 
 
 (1)
Net (gain)/loss7
 1
 3
 
 
 2
Net periodic postretirement benefit cost$29
 $1
 $10
 $1
 $2
 $4
(*)Excludes Southern Power since Southern Power did not participate in the qualified pension and postretirement benefit plans until December 2017.

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

(H)INCOME TAXES
See Note 5 to the financial statements of each registrant in Item 8 of the Form 10-K for additional tax information.
Federal Tax Reform Legislation
Following the enactment of the Tax Reform Legislation, the SEC staff issued Staff Accounting Bulletin 118 – "Income Tax Accounting Implications of the Tax Cuts and Jobs Act" (SAB 118), which provides for a measurement period of up to one year from the enactment date to complete accounting under GAAP for the tax effects of the legislation. Due to the complex and comprehensive nature of the enacted tax law changes, and their application under GAAP, the registrants consider all amounts recorded in the financial statements as a result of the Tax Reform Legislation to be "provisional" as discussed in SAB 118 and subject to revision. Each of the registrants is awaiting additional guidance from industry and income tax authorities in order to finalize its accounting. The ultimate impact of the Tax Reform Legislation on deferred income tax assets and liabilities and the related regulatory assets and liabilities cannot be determined at this time. See Note (B) under "Regulatory Matters" for additional information.
Current and Deferred Income Taxes
Tax Credit Carryforwards
Southern Company had federal ITC and PTC carryforwards (primarily related to Southern Power) totaling $2.3 billion as of June 30, 2018 compared to $2.1 billion as of December 31, 2017.
The federal ITC and PTC carryforwards begin expiring in 2034 and 2032, respectively, but are expected to be fully utilized by 2021. The estimated tax credit utilization reflects the 2018 abandonment loss related to certain Kemper County energy facility expenditures as well as the projected taxable gains on the various sale transactions described in Note (J) and "Legal Entity Reorganizations" herein. The expected utilization of tax credit carryforwards could be further delayed by numerous factors, including the acquisition of additional renewable projects and increased generation at existing wind facilities. The ultimate outcome of these matters cannot be determined at this time.
Effective Tax Rate
Each registrant'sDetails of significant changes in the effective tax rate for the six months ended June 30, 2018 varied significantly as compared to the corresponding period in 2017 due to the 14% lower 2018 federal tax rate resulting from the Tax Reform Legislation.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.PTCs, primarily at Southern Power.
Southern Company's effective tax benefit rate was (3.2)%39.8% for the sixthree months ended June 30, 2018March 31, 2019 compared to a benefit rate of (28.6)%10.8% for the corresponding period in 2017.2018. The effective tax rate increase was primarily due to the $3.1 billion pre-tax losstax impact from the sale of Gulf Power. See Note (K) for additional information.
Alabama Power
Alabama Power's effective tax rate was 21.9% for the three months ended March 31, 2019 compared to 26.3% for the corresponding period in 2018. The effective tax rate decrease was primarily due to the application in 2018 of the accounting order approved by the Alabama PSC in May 2018 related to the Tax Reform Legislation. 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.
Mississippi Power
Mississippi Power's effective tax rate was 15.5% for the three months ended March 31, 2019 compared to a benefit rate of (34.7)% for the corresponding period in 2018. The effective tax rate increase was primarily due to lower estimated losses on the Kemper IGCC net of the non-deductible AFUDC equity portion, recorded in 2017,2019, partially offset by the $1.1 billion pre-tax loss related to Plant Vogtle Units 3 and 4an increase in 2018, the reduction in the federal corporate income tax rate and the benefit from the flowback of excess deferred income taxes as a result of a settlement agreement reached with wholesale customers under the Tax Reform Legislation, as well as net state incomeMRA tariff. See Note (B) under "Mississippi Power" for additional information.
Southern Power
Southern Power's effective tax benefits relatedbenefit rate was (49.8)% for the three months ended March 31, 2019 compared to (647.0)% for the corresponding period in 2018. The effective tax benefit rate decrease was primarily due to changes in state apportionment rates arising fromfollowing the reorganization of Southern Power's legal entities that own and operate certain solar facilities and a reduction of tax benefits from wind PTCs primarily as discussed further herein.a result of the sale of a noncontrolling tax equity interest in SP Wind.
Southern Company Gas
Southern Company Gas' effective tax rate was 22.3% for the three months ended March 31, 2019 compared to 27.2% for the corresponding period in 2018. This decrease was primarily related to tax impacts of the goodwill impairment charge recorded in the first quarter 2018 and an increase in the flowback of excess deferred income taxes in 2019 primarily at Atlanta Gas Light as previously authorized by the Georgia PSC. See Note 32 to the financial statements of Southernunder "Southern Company under "Kemper County Energy Facility"Gas – Rate Proceedings" in Item 8 of the Form 10-K and Note (B) under "Kemper County Energy Facility" for additional information regarding the Kemper IGCC and Note (B) under "Nuclear Construction" for additional information regarding Plant Vogtle Units 3 and 4. See Note (B) under "Regulatory Matters" for additional information on the flowback of excess deferred income taxes.information.
(H) RETIREMENT BENEFITS
The Southern Company recognizes PTCs when wind energysystem has a qualified defined benefit, trusteed, pension plan covering substantially all employees, with the exception of employees at PowerSecure. The qualified pension plan is generated and sold (usingfunded in accordance with requirements of the prescribed KWH rate in applicable federal and state statutes), which may differ significantly from amounts computed on a quarterly basis using an overall estimated annual effective income tax rate.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 uses this method

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

sinceCompany 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 amount of PTCs can be significantly impacted by wind generation. This method can significantly affect the effective income tax rateSouthern Company system provides certain medical care and life insurance benefits for the period depending on the amount of pretax income.
Alabama Power
Alabama Power's effective tax rate was 22.8% for the six months ended June 30, 2018 compared to 40.2% for the corresponding period in 2017.retired employees through other postretirement benefit plans. The effective tax rate decrease was primarily duetraditional electric operating companies fund other postretirement trusts to the reductionextent 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 the federal corporate income tax rate and the benefit from the flowback of excess deferred income taxes as a resultItem 8 of the Tax Reform Legislation. See Note (B) under "Regulatory Matters – Alabama Power"Form 10-K for additional information.
Georgia Power
Georgia Power's effective taxComponents of the net periodic benefit rate was (53.5)%costs for the sixthree months ended June 30,March 31, 2019 and 2018 compared to an effective tax rate of 36.6% for the corresponding period in 2017. The effective tax rate decrease was primarily due to the $1.1 billion pre-tax loss related to the estimated probable loss on Plant Vogtle Units 3 and 4 recorded in 2018, partially offset by the reductionare presented in the federal corporate income tax rate. See Note (B) under "Nuclear Construction" for additional information.following tables.
Gulf Power
Gulf Power's effective tax rate was 3.3% for the six months ended June 30, 2018 compared to 39.8% for the corresponding period in 2017. The effective tax rate decrease was primarily due to the reduction in the federal corporate income tax rate and the benefit from the flowback
Three Months Ended
March 31, 2019
Southern
Company
 
Alabama
Power
 
Georgia
Power
 
Mississippi
Power
 Southern Power Southern Company Gas
 (in millions)
Pension Plans
Service cost$73
 $17
 $19
 $3
 $2
 $6
Interest cost123
 28
 39
 6
 1
 9
Expected return on plan assets(221) (51) (73) (10) (2) (15)
Amortization:           
Prior service costs
 
 
 
 
 (1)
Regulatory asset
 
 
 
 
 3
Net (gain)/loss30
 9
 11
 1
 
 1
Net periodic pension cost (income)$5
 $3
 $(4) $
 $1
 $3
Postretirement Benefits
Service cost$5
 $1
 $1
 $
 $
 $1
Interest cost17
 4
 7
 1
 
 2
Expected return on plan assets(16) (6) (6) 
 
 (2)
Amortization:           
Prior service costs1
 1
 
 
 
 
Regulatory asset
 
 
 
 
 2
Net (gain)/loss(1) 
 
 
 
 (1)
Net periodic postretirement benefit cost$6
 $
 $2
 $1
 $
 $2

168

Table of excess deferred income taxes as a result of the Tax Reform Legislation. See Note (B) under "Regulatory Matters – Gulf Power" for additional information.
Mississippi Power
Mississippi Power's effective tax rate was 18.7% for the six months ended June 30, 2018 compared to a benefit rate of (30.5)% for the corresponding period in 2017. The effective tax rate increase was primarily due to the $3.1 billion pre-tax loss on the Kemper IGCC, net of the non-deductible AFUDC equity portion, recorded in 2017, partially offset by the reduction in the federal corporate income tax rate as a result of the Tax Reform Legislation. See Note (B) under "Regulatory Matters – Mississippi Power" for additional information.
Southern Power
Southern Power's effective tax benefit rate was (1,386.5)% for the six months ended June 30, 2018 compared to a benefit rate of (114.7)% for the corresponding period in 2017. The effective tax rate decrease was primarily due to lower earnings before income taxes resulting from a $119 million asset impairment charge related to the sale of Southern Power's equity interests in two natural gas-fired operating facilities, Plant Oleander and Plant Stanton Unit A (together, the Florida Plants) described in Note (J) under "Southern Power – Sale of Florida Plants," as well as the reduction in the federal corporate income tax rate and the net state income tax benefits related to certain changes in apportionment rates arising from the reorganization of Southern Power's legal entities as described below.
Southern Power recognizes PTCs when wind energy is generated and sold (using the prescribed KWH rate in applicable federal and state statutes), which may differ significantly from amounts computed on a quarterly basis using an overall estimated annual effective income tax rate. Southern Power uses this method of recognition since the amount of PTCs can be significantly impacted by wind generation. This method can significantly affect the effective income tax rate for the period depending on the amount of pretax income.
Southern Company Gas
Southern Company Gas' effective tax rate was 39.1% for the six months ended June 30, 2018 compared to 38.5% for the corresponding period in 2017. This increase was primarily related to income taxes recorded related to the sale of Pivotal Home Solutions, including the reduction in deferred tax expense as a result of treating the sale as an asset sale for tax purposes, partially offset by the reduction in the federal corporate income tax rate and the benefit from the flowback of excess deferred income taxes as a result of the Tax Reform Legislation. See Note (B) underContents

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

"Regulatory Matters –
Three Months Ended
March 31, 2018
Southern
Company
 
Alabama
Power
 
Georgia
Power
 
Mississippi
Power
 Southern Power Southern Company Gas
 (in millions)
Pension Plans
Service cost$90

$19

$22

$4

$2

$8
Interest cost116

25

35

5

1

10
Expected return on plan assets(236)
(51)
(74)
(10)
(3)
(18)
Amortization:           
Prior service costs1









(1)
Regulatory asset
 
 
 
 
 3
Net (gain)/loss53

14

17

3

1

3
Net periodic pension cost (income)$24

$7

$

$2

$1

$5
Postretirement Benefits
Service cost$6
 $1
 $2
 $
 $
 $1
Interest cost19
 4
 7
 1
 
 2
Expected return on plan assets(17) (6) (6) 
 
 (2)
Amortization:           
Prior service costs2
 1
 
 
 
 
Regulatory asset
 
 
 
 
 1
Net (gain)/loss3
 
 2
 
 
 
Net periodic postretirement benefit cost$13
 $
 $5
 $1
 $
 $2

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

(I) FAIR VALUE MEASUREMENTS
As of March 31, 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 March 31, 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)(b)
$322
 $128
 $4
 $
 $454
Foreign currency derivatives
 38
 
 
 38
Investments in trusts:(c)(d)
         
Domestic equity682
 120
 
 
 802
Foreign equity60
 195
 
 
 255
U.S. Treasury and government agency securities
 283
 
 
 283
Municipal bonds
 73
 
 
 73
Pooled funds – fixed income
 14
 
 
 14
Corporate bonds24
 298
 
 
 322
Mortgage and asset backed securities
 72
 
 
 72
Private equity
 
 
 48
 48
Cash and cash equivalents1
 
 
 
 1
Other28
 4
 
 
 32
Cash equivalents907
 3
 
 
 910
Other investments9
 14
 
 
 23
Total$2,033
 $1,242
 $4
 $48
 $3,327
Liabilities:         
Energy-related derivatives(a)(b)
$466
 $106
 $23
 $
 $595
Interest rate derivatives
 35
 
 
 35
Foreign currency derivatives
 24
 
 
 24
Contingent consideration
 
 21
 
 21
Total$466
 $165
 $44
 $
 $675
          

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

 Fair Value Measurements Using:  
As of March 31, 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:(c)
        

Domestic equity446
 108
 
 
 554
Foreign equity60
 57
 
 
 117
U.S. Treasury and government agency securities
 18
 
 
 18
Municipal bonds
 1
 
 
 1
Corporate bonds24
 139
 
 
 163
Mortgage and asset backed securities
 24
 
 
 24
Private equity
 
 
 48
 48
Other5
 
 
 
 5
Cash equivalents569
 3
 
 
 572
Other investments
 14
 
 
 14
Total$1,104
 $370
 $
 $48
 $1,522
Liabilities:         
Energy-related derivatives$
 $7
 $
 $
 $7
          
Georgia Power         
Assets:         
Energy-related derivatives$
 $9
 $
 $
 $9
Nuclear decommissioning trusts:(c)(d)
         
Domestic equity236
 1
 
 
 237
Foreign equity
 134
 
 
 134
U.S. Treasury and government agency securities
 265
 
 
 265
Municipal bonds
 72
 
 
 72
Corporate bonds
 160
 
 
 160
Mortgage and asset backed securities
 47
 
 
 47
Other23
 4
 
 
 27
Total$259
 $692
 $
 $
 $951
Liabilities:         
Energy-related derivatives$
 $16
 $
 $
 $16
Interest rate derivatives
 2
 
 
 2
Total$
 $18
 $
 $
 $18
          

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

 Fair Value Measurements Using:  
As of March 31, 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 equivalents202
 
 
 
 202
Total$202
 $3
 $
 $
 $205
Liabilities:         
Energy-related derivatives$
 $6
 $
 $
 $6
          
Southern Power         
Assets:         
Energy-related derivatives$
 $1
 $
 $
 $1
Foreign currency derivatives
 38
 
 

38
Cash equivalents10
 
 
 
 10
Total$10
 $39
 $
 $
 $49
Liabilities:         
Energy-related derivatives$
 $3
 $
 $
 $3
Foreign currency derivatives
 24
 
 
 24
Contingent consideration
 
 21
 
 21
Total$

$27

$21

$

$48
          
Southern Company Gas         
Assets:         
Energy-related derivatives(a)(b)
$322
 $108
 $4
 $
 $434
Non-qualified deferred compensation trusts:         
Domestic equity
 11
 
 
 11
Foreign equity
 4
 
 
 4
Pooled funds – fixed income
 14
 
 
 14
Cash equivalents1
 
 
 
 1
Cash equivalents13
 
 
 
 13
Total$336

$137

$4

$

$477
Liabilities:         
Energy-related derivatives(a)(b)
$466
 $73
 $23
 $
 $562
(a)
Energy-related derivatives exclude $11 million associated with premiums and certain weather derivatives accounted for based on intrinsic value rather than fair value.
(b)
Energy-related derivatives exclude cash collateral of $190 million.
(c)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.
(d)
Includes investment securities pledged to creditors and collateral received and excludes payables related to the securities lending program. As of March 31, 2019, approximately $72 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.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

Southern Company, Gas"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 and dividends and excluding the funds' expenses, increased for the three months ended March 31, 2019 and decreased for the three months ended March 31, 2018 by the amounts shown in the table below. 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
March 31, 2019
Three Months
Ended
March 31, 2018
 (in millions)
Southern Company$152
$(11)
Alabama Power87
(5)
Georgia Power65
(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) under "Southern Company Gas – Sale of Pivotal Home Solutions" for additional information.information on how these derivatives are used.
Legal Entity Reorganizations
In March 2018, Southern Power substantially completed a legal entity reorganization of various direct and indirect subsidiaries that own and operate substantially all of its solar facilities, including certain subsidiaries owned in partnership with various third parties. The reorganization resulted in net state tax benefits related to certain changes in apportionment rates totaling approximately $50 million, which were recorded in the first quarter 2018. In April 2018, Southern Power completed the final stageFor fair value measurements of the reorganization resulting in additional net state tax benefitsinvestments 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 approximately $4 million.
Southern Power is pursuing the sale of a noncontrolling interest in a portfolio of eight operating wind facilitieseach business day through the usenet 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 third-party tax equity, which, if successful, is expectedthe 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 close in the fourth quarter 2018. In the third quarter 2018, various direct and indirect subsidiariesestablish a plan for providing reasonable assurance of Southern Power that own and operate these wind facilities are expected to be reorganized under a new holding company in which the tax equity partner would invest. The reorganization is expected to result in estimated net state tax benefits totaling approximately $10 million related to certain changes in apportionment rates. The ultimate outcome of this matter cannot be determined at this time.
Unrecognized Tax Benefits
funds for future decommissioning. See Note 56 to the financial statements of each registrant under "Unrecognized Tax Benefits""Nuclear Decommissioning" in Item 8 of the Form 10-K for additional information.
The registrants had no unrecognized tax benefits as of June 30, 2018. ItSouthern Power has contingent payment obligations related to certain acquisitions whereby Southern Power is reasonably possible thatprimarily obligated to make generation-based payments to the amountseller, which commenced at the commercial operation of the unrecognized tax benefits could change within 12 months.respective facility and continue through 2026. The settlement of federal and state audits could impactobligation is categorized as Level 3 under Fair Value Measurements as the balances significantly. At this time, an estimate offair value is determined using significant unobservable inputs for the range of reasonably possible outcomes cannot be determined.
The IRS has finalized its audits of Southern Company's consolidated income tax returns through 2016,forecasted facility generation in MW-hours, as well as other inputs such as a fixed dollar amount per MW-hour, and a discount rate.

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The fair value of contingent consideration reflects the pre-Merger Southern Company Gas tax returns. Southern Companynet present value of expected payments and any periodic change arising from forecasted generation is expected to be immaterial.
As of March 31, 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 participantpractical expedient totaled $48 million and unfunded commitments related to the private equity investments totaled $49 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 Compliance Assurance Processfunds are liquidated.
As of March 31, 2019, other financial instruments for which the IRS. The audits for Southern Company's state income tax returns have either been concluded, or the statute of limitations has expired, for years prior to 2011.carrying amount did not equal fair value were as follows:
 
Southern
Company
Alabama PowerGeorgia PowerMississippi PowerSouthern Power
Southern Company Gas(*)
 (in millions)
Long-term debt, including securities due within one year:    
Carrying amount$42,535
$7,921
$10,910
$1,619
$4,995
$5,928
Fair value43,910
8,424
11,249
1,619
5,131
6,176
(I)(*)DERIVATIVESThe long-term debt of Southern Company Gas is recorded at amortized cost, including the fair value adjustments at the effective date of the Merger. 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 March 31, 2019, the fair value of Southern Company Gas' Level 3 physical natural gas forward contracts was $19 million. Since commodity contracts classified as Level 3 typically include a combination of observable and unobservable components, the changes in fair value may include amounts due in part to observable market factors, or changes to assumptions on the unobservable components. The following table includes transfers to Level 3, which represent the fair value of Southern Company Gas' commodity derivative contracts that include a significant unobservable component for the first time during the period.
 Three Months Ended March 31, 2019
 (in millions)
Beginning balance$
Transfers to Level 3(30)
Changes in fair value11
Ending balance$(19)
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

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(UNAUDITED)

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 $0.07 to $1.15 per mmBtu). Forward price increases (decreases) as of March 31, 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 (D)(I) for additional fair value information. In the statements of cash flows, theany cash impacts of settled energy-related and interest rate derivatives are recorded as operating activities. TheAny cash impacts of settled foreign currency derivatives are classified as operating or financing activities to correspond with classification of the hedged interest or principal, respectively.
The registrants adopted ASU 2017-12 as of January 1, 2018. See Note (A)1 to the financial statements under "Recently Adopted Accounting StandardsOther""Financial Instruments" in Item 8 of the Form 10-K for additional information.

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

Energy-Related Derivatives
Southern Company, theThe 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 isare expected to continue to mitigate price volatility. The Florida PSC approved a moratorium on Gulf Power's fuel-hedging program until January 1, 2021. The moratorium does not have an impact on the recovery of existing hedges entered into under the previously-approved hedging program. The traditional electric operating companies (with respect to wholesale generating capacity) and Southern Power have limited exposure to market volatility in energy-related commodity prices because their long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, the traditional electric operating companies and Southern Power may be exposed to market volatility in energy-related commodity prices to the extent any uncontracted capacity is used to sell electricity. Southern Company Gas retains exposure to price changes that can, in a volatile energy market, be material and can adversely affect its results of operations.
Southern Company Gas also enters into weather derivative contracts as economic hedges of operating margins in the event of warmer-than-normal weather. Exchange-traded options are carried at fair value, with changes reflected in operating revenues. Non-exchange-traded options are accounted for using the intrinsic value method. Changes in the intrinsic value for non-exchange-traded contracts are reflected in operating revenues.

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Energy-related derivative contracts are accounted for under one of three methods:
Regulatory Hedges — Energy-related derivative contracts which are designated as regulatory hedges relate primarily to the traditional electric operating companies' and the natural gas distribution utilities' fuel-hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through the respective fuel cost recovery clauses.
Cash Flow Hedges — Gains and losses on energy-related derivatives designated as cash flow hedges (which are mainly used to hedge anticipated purchases and sales) are initially deferred in 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.

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

At June 30, 2018,March 31, 2019, the net volume of energy-related derivative contracts for natural gas positions, for the Southern Company system, together with the longest hedge date over which the respective entity is hedging its exposure to the variability in future cash flows for forecasted transactions and the longest non-hedge date for derivatives not designated as hedges, were as follows:
Net
Purchased
mmBtu
 
Longest
Hedge
Date
 
Longest
Non-Hedge
Date
Net
Purchased
mmBtu
 
Longest
Hedge
Date
 
Longest
Non-Hedge
Date
(in millions) (in millions) 
Southern Company(*)
701 2022 2029538 2022 2029
Alabama Power82 2022 72 2022 
Georgia Power174 2022 153 2022 
Gulf Power13 2020 
Mississippi Power66 2022 61 2022 
Southern Power14 2020 9 2020 
Southern Company Gas(*)
352 2020 2029243 2021 2029
(*)Southern Company's and Southern Company Gas' derivative instruments include both long and short natural gas positions. A long position is a contract to purchase natural gas and a short position is a contract to sell natural gas. Southern Company Gas' volume represents the net of long natural gas positions of 3.93.8 billion mmBtu and short natural gas positions of 3.6 billion mmBtu as of June 30, 2018,March 31, 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 1740 million mmBtu for Southern Company, 3which includes 6 million mmBtu for Alabama Power, 612 million mmBtu for Georgia Power, 1 million mmBtu for Gulf Power, 25 million mmBtu for Mississippi Power, and 513 million mmBtu for Southern Power.
For cash flow hedges of energy-related derivatives, the amountsestimated pre-tax gains (losses) expected to be reclassified from accumulated OCI to earnings for the next 12-month period ending June 30, 2019March 31, 2020 are immaterial for all registrants.
Interest Rate Derivatives
Southern Company and certain subsidiaries may also enter into interest rate derivatives to hedge exposure to changes in interest rates. The derivatives employed as hedging instruments are structured to minimize ineffectiveness. Derivatives related to existing variable rate securities or forecasted transactions are accounted for as cash flow

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(UNAUDITED)

hedges where the derivatives' fair value gains or losses are recorded in OCI and are reclassified into earnings at the same time and presented on the same income statement line item as the earnings effect of the hedged transactions. Derivatives related to existing fixed rate securities are accounted for as fair value hedges, where the derivatives' fair value gains or losses and hedged items' fair value gains or losses are both recorded directly to earnings on the same income statement line item. Fair value gains or losses on derivatives that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

At June 30, 2018,March 31, 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, 2018
Notional
Amount
 
Interest
Rate
Received
Weighted
Average
Interest
Rate Paid
Hedge
Maturity
Date
 Fair Value Gain (Loss) at March 31, 2019
(in millions)   (in millions)(in millions)   (in millions)
Fair Value Hedges of Existing DebtFair Value Hedges of Existing Debt  Fair Value Hedges of Existing Debt  
Southern Company(*)
$300
 2.75%3-month
LIBOR + 0.92%
June 2020 $(6)$300
 2.75%3-month LIBOR+0.92%June 2020 $(3)
Southern Company(*)
1,500
 2.35%1-month
LIBOR + 0.87%
July 2021 (57)1,500
 2.35%1-month LIBOR+0.87%July 2021 (30)
Georgia Power500
 1.95%3-month
LIBOR + 0.76%
December 2018 (3)200
 4.25%3-month LIBOR+2.46%December 2019 (2)
Georgia Power200
 4.25%3-month
LIBOR + 2.46%
December 2019 (3)
Southern Company Consolidated$2,500
 $(69)$2,000
 $(35)
(*)Represents the Southern Company parent entity.
The estimated pre-tax gains (losses) related to interest rate derivatives expected to be reclassified from accumulated OCI to interest expense for the next 12-month period ending June 30, 2019March 31, 2020 are $(18)$(19) million for Southern Company and immaterial for all other registrants. Southern Company and certain subsidiaries have deferredDeferred gains and losses related to interest rate derivatives are expected to be amortized into earnings through 2046.2046 for the Southern Company parent entity, 2035 for Alabama Power, 2037 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 also enter into foreign currency derivatives to hedge exposure to changes in foreign currency exchange rates, such as that arising from the issuance of debt denominated in a currency other than U.S. dollars. Derivatives related to forecasted transactions are accounted for as cash flow hedges where the derivatives' fair value gains or losses are recorded in OCI and are reclassified into earnings at the same time and on the same income statement line as the earnings effect of the hedged transactions, including foreign currency gains or losses arising from changes in the U.S. currency exchange rates. The derivatives employed as hedging instruments are structured to minimize ineffectiveness.
At June 30, 2018,March 31, 2019, the following foreign currency derivatives were outstanding:

Pay NotionalPay RateReceive NotionalReceive RateHedge
Maturity Date
Fair Value Gain (Loss) at June 30, 2018Pay NotionalPay RateReceive NotionalReceive RateHedge
Maturity Date
Fair Value Gain (Loss) at March 31, 2019

(in millions) (in millions)  (in millions)(in millions) (in millions)  (in millions)
Cash Flow Hedges of Existing DebtCash Flow Hedges of Existing Debt    Cash Flow Hedges of Existing Debt    
Southern Power$677
2.95%600
1.00%June 2022$54
$677
2.95%600
1.00%June 2022$2
Southern Power564
3.78%500
1.85%June 202655
564
3.78%500
1.85%June 202611
Total$1,241
 1,100
 $109
$1,241
 1,100
 $13

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(UNAUDITED)

The estimated pre-tax gains (losses) related to Southern Power's foreign currency derivatives that willexpected to be reclassified from accumulated OCI to earnings for the next 12-month period ending June 30, 2019March 31, 2020 are $(23) million for Southern Company and Southern Power.

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

$(24) 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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(UNAUDITED)

The fair value of energy-related derivatives, interest rate derivatives, and foreign currency derivatives was reflected in the balance sheets as follows:
As of June 30, 2018As of December 31, 2017As of March 31, 2019As of December 31, 2018
Derivative Category and Balance Sheet LocationAssetsLiabilitiesAssetsLiabilitiesAssetsLiabilitiesAssetsLiabilities
(in millions)(in millions)
Southern Company  
Derivatives designated as hedging instruments for regulatory purposes  
Energy-related derivatives:  
Other current assets/Other current liabilities$16
$12
$10
$43
$12
$10
$8
$23
Other deferred charges and assets/Other deferred credits and liabilities5
27
7
24
11
21
9
26
Assets held for sale, current/Liabilities held for sale, current
8





6
Assets held for sale/Liabilities held for sale
4


Total derivatives designated as hedging instruments for regulatory purposes$21
$51
$17
$67
$23
$31
$17
$55
Derivatives designated as hedging instruments in cash flow and fair value hedges  
Energy-related derivatives:  
Other current assets/Other current liabilities$2
$3
$3
$14
$1
$3
$3
$7
Other deferred charges and assets/Other deferred credits and liabilities1
1



1
1
2
Interest rate derivatives:  
Other current assets/Other current liabilities
15
1
4

20

19
Other deferred charges and assets/Other deferred credits and liabilities
53

34

15

30
Foreign currency derivatives:  
Other current assets/Other current liabilities
23

23

24

23
Other deferred charges and assets/Other deferred credits and liabilities132

129

38

75

Total derivatives designated as hedging instruments in cash flow and fair value hedges$135
$95
$133
$75
$39
$63
$79
$81
Derivatives not designated as hedging instruments  
Energy-related derivatives:  
Other current assets/Other current liabilities$239
$272
$380
$437
$259
$291
$561
$575
Other deferred charges and assets/Other deferred credits and liabilities189
246
170
215
171
269
180
325
Total derivatives not designated as hedging instruments$428
$518
$550
$652
$430
$560
$741
$900
Gross amounts recognized$584
$664
$700
$794
$492
$654
$837
$1,036
Gross amounts offset(a)
$(306)$(489)$(405)$(598)$(333)$(523)$(524)$(801)
Net amounts recognized in the Balance Sheets(b)
$278
$175
$295
$196
$159
$131
$313
$235
  

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(UNAUDITED)

As of June 30, 2018As of December 31, 2017As of March 31, 2019As of December 31, 2018
Derivative Category and Balance Sheet LocationAssetsLiabilitiesAssetsLiabilitiesAssetsLiabilitiesAssetsLiabilities
(in millions)(in millions)
Alabama Power  
Derivatives designated as hedging instruments for regulatory purposes  
Energy-related derivatives:  
Other current assets/Other current liabilities$6
$3
$2
$6
$3
$2
$3
$4
Other deferred charges and assets/Other deferred credits and liabilities2
6
2
4
3
5
3
6
Total derivatives designated as hedging instruments for regulatory purposes$8
$9
$4
$10
$6
$7
$6
$10
Gross amounts recognized$8
$9
$4
$10
$6
$7
$6
$10
Gross amounts offset$(4)$(4)$(4)$(4)$(5)$(5)$(4)$(4)
Net amounts recognized in the Balance Sheets$4
$5
$
$6
$1
$2
$2
$6
  
Georgia Power  
Derivatives designated as hedging instruments for regulatory purposes  
Energy-related derivatives:  
Other current assets/Other current liabilities$5
$5
$2
$9
$4
$5
$2
$8
Other deferred charges and assets/Other deferred credits and liabilities2
14
4
10
5
11
4
13
Total derivatives designated as hedging instruments for regulatory purposes$7
$19
$6
$19
$9
$16
$6
$21
Derivatives designated as hedging instruments in cash flow and fair value hedges  
Interest rate derivatives:  
Other current assets/Other current liabilities$
$5
$
$4
$
$2
$
$2
Other deferred charges and assets/Other deferred credits and liabilities
1

1
Total derivatives designated as hedging instruments in cash flow and fair value hedges$
$6
$
$5
$
$2
$
$2
Gross amounts recognized$7
$25
$6
$24
$9
$18
$6
$23
Gross amounts offset$(7)$(7)$(6)$(6)$(8)$(8)$(6)$(6)
Net amounts recognized in the Balance Sheets$
$18
$
$18
$1
$10
$
$17
  
Gulf Power 
Derivatives designated as hedging instruments for regulatory purposes 
Energy-related derivatives: 
Other current assets/Other current liabilities$
$8
$
$14
Other deferred charges and assets/Other deferred credits and liabilities
4

7
Total derivatives designated as hedging instruments for regulatory purposes$
$12
$
$21
Gross amounts recognized$
$12
$
$21
Gross amounts offset$
$
$
$
Net amounts recognized in the Balance Sheets$
$12
$
$21

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

As of June 30, 2018As of December 31, 2017As of March 31, 2019As of December 31, 2018
Derivative Category and Balance Sheet LocationAssetsLiabilitiesAssetsLiabilitiesAssetsLiabilitiesAssetsLiabilities
(in millions)
 (in millions)
Mississippi Power  
Derivatives designated as hedging instruments for regulatory purposes  
Energy-related derivatives:  
Other current assets/Other current liabilities$2
$3
$1
$6
$2
$2
$1
$3
Other deferred charges and assets/Other deferred credits and liabilities1
6
1
3
1
4
2
6
Total derivatives designated as hedging instruments for regulatory purposes$3
$9
$2
$9
$3
$6
$3
$9
Derivatives designated as hedging instruments in cash flow and fair value hedges 
Interest rate derivatives: 
Other current assets/Other current liabilities$
$
$1
$
Total derivatives designated as hedging instruments in cash flow and fair value hedges$
$
$1
$
Gross amounts recognized$3
$9
$3
$9
$3
$6
$3
$9
Gross amounts offset$(2)$(2)$(2)$(2)$(3)$(3)$(2)$(2)
Net amounts recognized in the Balance Sheets$1
$7
$1
$7
$
$3
$1
$7
  
Southern Power  
Derivatives designated as hedging instruments in cash flow and fair value hedges  
Energy-related derivatives:  
Other current assets/Other current liabilities$2
$2
$3
$11
$1
$2
$3
$6
Other deferred charges and assets/Other deferred credits and liabilities1
1



1
1
2
Foreign currency derivatives:  
Other current assets/Other current liabilities
23

23

24

23
Other deferred charges and assets/Other deferred credits and liabilities132

129

38

75

Total derivatives designated as hedging instruments in cash flow and fair value hedges$135
$26
$132
$34
$39
$27
$79
$31
Derivatives not designated as hedging instruments 
Energy-related derivatives: 
Other current assets/Other current liabilities$
$
$
$2
Gross amounts recognized$135
$26
$132
$36
$39
$27
$79
$31
Gross amounts offset$(2)$(2)$(3)$(3)$(1)$(1)$(3)$(3)
Net amounts recognized in the Balance Sheets$133
$24
$129
$33
$38
$26
$76
$28
 
Southern Company Gas 
Derivatives designated as hedging instruments for regulatory purposes 
Energy-related derivatives: 
Assets from risk management activities/Liabilities from risk management activities-current$3
$1
$2
$8
Other deferred charges and assets/Other deferred credits and liabilities1


1
Total derivatives designated as hedging instruments for regulatory purposes$4
$1
$2
$9
Derivatives designated as hedging instruments in cash flow and fair value hedges 
Energy-related derivatives: 
Assets from risk management activities/Liabilities from risk management activities-current$
$1
$
$1
Total derivatives designated as hedging instruments in cash flow and fair value hedges$
$1
$
$1

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(UNAUDITED)

As of June 30, 2018As of December 31, 2017As of March 31, 2019As of December 31, 2018
Derivative Category and Balance Sheet LocationAssetsLiabilitiesAssetsLiabilitiesAssetsLiabilitiesAssetsLiabilities
(in millions)(in millions)
 
Southern Company Gas 
Derivatives designated as hedging instruments for regulatory purposes 
Energy-related derivatives: 
Assets from risk management activities/Liabilities from risk management activities-current$3
$1
$5
$8
Other deferred charges and assets/Other deferred credits and liabilities
1


Total derivatives designated as hedging instruments for regulatory purposes$3
$2
$5
$8
Derivatives designated as hedging instruments in cash flow and fair value hedges 
Energy-related derivatives: 
Assets from risk management activities/Liabilities from risk management activities-current$
$1
$
$3
Derivatives not designated as hedging instruments  
Energy-related derivatives:  
Assets from risk management activities/Liabilities from risk management activities-current$239
$272
$379
$434
$259
$291
$559
$574
Other deferred charges and assets/Other deferred credits and liabilities189
246
170
215
171
269
180
325
Total derivatives not designated as hedging instruments$428
$518
$549
$649
$430
$560
$739
$899
Gross amounts of recognized$431
$521
$554
$660
$434
$562
$741
$909
Gross amounts offset(a)
$(291)$(474)$(390)$(583)$(316)$(506)$(508)$(785)
Net amounts recognized in the Balance Sheets(b)
$140
$47
$164
$77
$118
$56
$233
$124
(a)Gross amounts offset include cash collateral held on deposit in broker margin accounts of $183$190 million and $193$277 million as of June 30, 2018March 31, 2019 and December 31, 2017,2018, respectively.
(b)Net amounts of derivative instruments outstanding exclude premium and intrinsic value associated with weather derivatives of $3$11 million and $11$8 million as of June 30, 2018March 31, 2019 and December 31, 2017,2018, respectively.

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

At June 30, 2018March 31, 2019 and December 31, 2017,2018, 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, 2018
Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at March 31, 2019Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at March 31, 2019
Derivative Category and Balance Sheet
Location
Southern
Company(*)
Alabama
Power
Georgia
Power
Gulf
Power
Mississippi
Power
Southern Company Gas(*)
Southern
Company(*)
Alabama
Power
Georgia
Power
Mississippi
Power
Southern Company Gas(*)
(in millions) (in millions)
Energy-related derivatives:  
Other regulatory assets, current$(4)$(1)$(1)$(8)$(1)$(1)$(5)$(1)$(2)$(1)$(1)
Other regulatory assets, deferred(20)(4)(11)(4)(5)
(11)(2)(6)(3)
Assets held for sale, current(8)




Assets held for sale(4)




Other regulatory liabilities, current8
4



4
7
1
1
1
4
Total energy-related derivative gains (losses)$(28)$(1)$(12)$(12)$(6)$3
$(9)$(2)$(7)$(3)$3
(*)Fair value gains and losses recorded in regulatory assets and liabilities include cash collateral held on deposit in broker margin accounts of $2 million at June 30, 2018.March 31, 2019.
Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at December 31, 2017
Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at December 31, 2018Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at December 31, 2018
Derivative Category and Balance Sheet
Location
Southern
Company(*)
Alabama
Power
Georgia
Power
Gulf
Power
Mississippi
Power
Southern Company Gas(*)
Southern
Company
Alabama
Power
Georgia
Power
Mississippi
Power
Southern Company Gas
(in millions) (in millions)
Energy-related derivatives:  
Other regulatory assets, current$(34)$(4)$(7)$(14)$(5)$(4)$(19)$(3)$(6)$(2)$(8)
Other regulatory assets, deferred(18)(3)(6)(7)(2)
(16)(3)(9)(4)
Assets held for sale, current(6)



Other regulatory liabilities, current7




7
1



1
Other regulatory liabilities, deferred1
1




Total energy-related derivative gains (losses)$(44)$(6)$(13)$(21)$(7)$3
$(40)$(6)$(15)$(6)$(7)
(*)Fair value gains and losses recorded in regulatory assets and liabilities include cash collateral held on deposit in broker margin accounts of $6 million at December 31, 2017.

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For the three and six months ended June 30,March 31, 2019 and 2018, and 2017, the pre-tax effects of cash flow hedge accounting on accumulated OCI were as follows:
Gain (Loss) Recognized in OCI on DerivativeFor the Three Months
Ended June 30,
For the Six Months
Ended June 30,
For the Three Months
Ended March 31,
201820172018201720192018
(in millions)(in millions)
Southern Company  
Energy-related derivatives$
$(9)$12
$(20)$
$12
Interest rate derivatives
(1)(2)(1)
(2)
Foreign currency derivatives(73)71
(21)67
(39)53
Total$(73)$61
$(11)$46
$(39)$63
Southern Power  
Energy-related derivatives$(1)$(7)$10
$(15)$
$11
Foreign currency derivatives(73)71
(21)67
(39)53
Total$(74)$64
$(11)$52
$(39)$64
Southern Company Gas 
Energy-related derivatives$1
$(2)$2
$(4)
For the three and six months ended June 30,March 31, 2019 and 2018, and 2017, the pre-tax effects of energy-related derivatives and interest rate derivatives designated as cash flow hedging instruments on accumulated OCI were immaterial for the other registrants.
For the three and six months ended June 30, 2017, there was no material ineffectiveness recorded in earnings for any registrant. Upon the adoption of ASU 2017-12, beginning in 2018, ineffectiveness was no longer separately measured and recorded in earnings. See Note (A) for additional information.

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

For the three and six months ended June 30,March 31, 2019 and 2018, and 2017, the pre-tax effects of cash flow and fair value hedge accounting on income were as follows:
 Location and Amount of Gain (Loss) Recognized in Income on Cash Flow and Fair Value Hedging RelationshipsFor the Three Months
Ended June 30,
For the Six Months
Ended June 30,
 
 2018201720182017
  (in millions)(in millions)
 Southern Company    
 Depreciation and amortization$783
$754
$1,552
$1,469
 
Gain (loss) on cash flow hedges(a)
    
 Energy-related derivatives1
(2)2
(6)
 Interest expense, net of amounts capitalized(470)(424)(928)(840)
 
Gain (loss) on cash flow hedges(a)
    
 Interest rate derivatives(6)(5)(11)(10)
 Foreign currency derivatives(7)(5)(12)(12)
 
Gain (loss) on fair value hedges(b)
    
 Interest rate derivatives(7)7
(31)(1)
 Other income (expense), net78
52
138
98
 
Gain (loss) on cash flow hedges(a)(c)
    
 Foreign currency derivatives(73)79
(37)96
 Cost of natural gas228
232
949
951
 
Gain (loss) on cash flow hedges(a)
    
 Energy-related derivatives

(2)
 Alabama Power    
 Interest expense, net of amounts capitalized$(80)$(77)$(158)$(153)
 
Gain (loss) on cash flow hedges(a)
    
 Interest rate derivatives(1)(2)(3)(3)
 Georgia Power    
 Interest expense, net of amounts capitalized$(102)$(104)$(208)$(205)
 
Gain (loss) on cash flow hedges(a)
    
 Interest rate derivatives(2)(1)(3)(3)
 
Gain (loss) on fair value hedges(b)
    
 Interest rate derivatives2

(1)(1)
 Mississippi Power    
 Interest expense, net of amounts capitalized$(21)$(17)$(39)$(37)
 
Gain (loss) on cash flow hedges(a)
    
 Interest rate derivatives(1)
(1)(1)
      

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

 Location and Amount of Gain (Loss) Recognized in Income on Cash Flow and Fair Value Hedging RelationshipsFor the Three Months
Ended June 30,
For the Six Months
Ended June 30,
 
 2018201720182017
  (in millions)(in millions)
 Southern Power    
 Depreciation and amortization$125
$129
$240
$247
 
Gain (loss) on cash flow hedges(a)
    
 Energy-related derivatives1
(2)2
(6)
 Interest expense, net of amounts capitalized(46)(48)(93)(97)
 
Gain (loss) on cash flow hedges(a)
    
 Foreign currency derivatives(7)(5)(12)(12)
 Other income (expense), net2
2
5
(2)
 
Gain (loss) on cash flow hedges(a)(c)
    
 Foreign currency derivatives(73)79
(37)96
      
 Southern Company Gas    
 Cost of natural gas$228
$232
$949
$951
 
Gain (loss) on cash flow hedges(a)
    
 Energy-related derivatives

(2)
 Location and Amount of Gain (Loss) Recognized in Income on Cash Flow and Fair Value Hedging RelationshipsFor the Three Months
Ended March 31,
 
 20192018
  (in millions)
 Southern Company  
 Total depreciation and amortization$751
$769
 
Gain (loss) on energy-related cash flow hedges(a)
(3)1
 Total interest expense, net of amounts capitalized(430)(458)
 
Gain (loss) on interest rate cash flow hedges(a)
(5)(5)
 
Gain (loss) on foreign currency cash flow hedges(a)
(6)(5)
 
Gain (loss) on interest rate fair value hedges(b)
14
(24)
 Total other income (expense), net78
60
 
Gain (loss) on foreign currency cash flow hedges(a)(c)
(24)36
 Southern Power  
 Total depreciation and amortization$119
$114
 
Gain (loss) on energy-related cash flow hedges(a)
(3)1
 Total interest expense, net of amounts capitalized(44)(47)
 
Gain (loss) on foreign currency cash flow hedges(a)
(6)(5)
 Total other income (expense), net2
3
 
Gain (loss) on foreign currency cash flow hedges(a)(c)
(24)36
(a)Amounts reflect gains or losses on cash flow hedges that were reclassifiedReclassified from accumulated OCI into income.earnings.
(b)For fair value hedges, presented above, generally 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.

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For the three and six months ended June 30,March 31, 2019 and 2018, and 2017, 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 Gulf Powerthe traditional electric operating companies and Southern Company Gas.
As of June 30, 2018March 31, 2019 and December 31, 2017,2018, 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 ItemsAs of June 30, 2018As of December 31, 2017
As of June 30, 2018As of December 31, 2017

(in millions) (in millions)
Southern Company     
Securities due within one year$(497)$(746) $3
$3
Long-term Debt(2,528)(2,553) 63
35
      
Georgia Power     
Securities due within one year$(497)$(746) $3
$3
Long-term Debt(497)(498) 3
1

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)


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 ItemsAs of March 31, 2019As of December 31, 2018
As of March 31, 2019As of December 31, 2018

(in millions) (in millions)
Southern Company     
Securities due within one year$(499)$(498) $1
$2
Long-term debt(2,065)(2,052) 28
41
      
Georgia Power     
Securities due within one year$(499)$(498) $1
$2
Long-term debt

 

For the three and six months ended June 30,March 31, 2019 and 2018, and 2017, 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) Gain (Loss)
 Three Months Ended June 30, 
Six Months Ended
June 30,
 Three Months Ended March 31,
Derivatives in Non-Designated Hedging RelationshipsStatements of Income Location20182017 20182017Statements of Income Location20192018
 (in millions) (in millions) (in millions)
Southern Company    
Energy-related derivatives:
Natural gas revenues(*)
$(28)$16
 $(43)$65
Natural gas revenues(*)
$33
$(15)
Cost of natural gas2
(2) 4
(4)Cost of natural gas8
2
Total derivatives in non-designated hedging relationshipsTotal derivatives in non-designated hedging relationships$(26)$14
 $(39)$61
Total derivatives in non-designated hedging relationships$41
$(13)
Southern Company Gas    
Energy-related derivatives:
Natural gas revenues(*)
$(28)$16
 $(43)$65
Cost of natural gas2
(2) 4
(4)
Total derivatives in non-designated hedging relationships$(26)$14
 $(39)$61
(*)Excludes immaterial gains (losses) recorded in natural gas revenues associated with weather derivatives of $15 million for the sixthree months ended June 30, 2017March 31, 2019 and immaterial amounts for all other periods presented.2018.
For the three and six months ended June 30,March 31, 2019 and 2018, and 2017, the pre-tax effects of energy-related derivatives and interest rate derivatives not designated as hedging instruments were immaterial for the traditional electric operating companies and Southern Power.
Contingent Features
Southern Company, the traditional electric operating companies, Southern Power, and Southern Company Gas do not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of various credit rating changes of certain Southern Company subsidiaries. At June 30, 2018,March 31, 2019, the registrants had no collateral posted with derivative counterparties to satisfy these arrangements.
For the registrants with interest rate derivatives at June 30, 2018,March 31, 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, 2018,March 31, 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

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(UNAUDITED)

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, 2018,March 31, 2019, cash collateral posted in these accounts was immaterial. Southern Company Gas maintains accounts with brokers or the clearing houses of certain exchanges to facilitate financial derivative transactions. Based on the value of the

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

positions in these accounts and the associated margin requirements, Southern Company Gas may be required to deposit cash into these accounts. At June 30, 2018,March 31, 2019, cash collateral held on deposit in broker margin accounts was $183$190 million.
Southern Company, the traditional electric operating companies, Southern Power, and Southern Company GasThe registrants are exposed to losses related to financial instruments in the event of counterparties' nonperformance. Southern Company, the traditional electric operating companies, Southern Power, and Southern Company GasThe 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. Southern Company, the traditional electric operating companies, Southern Power, and Southern Company GasThe registrants have also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate Southern Company's, the traditional electric operating companies', Southern Power's, and Southern Company Gas'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.
Southern Company, the traditional electric operating companies, Southern Power, and Southern Company GasThe registrants do not anticipate a material adverse effect on thetheir respective financial statements as a result of counterparty nonperformance.

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(UNAUDITED)

(J)ACQUISITIONS AND DISPOSITIONS
(K) ACQUISITIONS AND DISPOSITIONS
See Note 15 to the financial statements in Item 8 of the Form 10-K for additional information.
Southern Company's Sale of Gulf PowerCompany
On May 20, 2018,January 1, 2019, Southern Company entered into a stock purchase agreement (Gulf Power SPA) with NextEra Energy and its wholly-owned subsidiary 700 Universe, LLC, which provides forcompleted 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 $5.75approximately $5.8 billion (less the amount$1.3 billion of indebtedness assumed at closing, which is currently estimated at approximately $1.4 billion)assumed), subject to (i) customary adjustments for indebtedness and working capital and (ii) reduction byadjustments. The preliminary gain associated with the amount (if any) by which Gulf Power fails to meet a specified capital expenditure target.
The Gulf Power SPA contains customary representations, warranties, and covenants of Southern Company, 700 Universe, LLC, and NextEra Energy. These covenants include, among others, an obligation of Southern Company to cause Gulf Power to operate its business in the ordinary course until the sale is consummated and an obligation for each of the parties to use reasonable best efforts to obtain the governmental and regulatory approvals described below.
The completion of the sale is subject to the satisfaction or waiver of certain closing conditions, including, among others, (i) the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act (HSR Act), (ii) approval by the FERC and the Federal Communications Commission, (iii) the entry into certain ancillary agreements, including transmission-related agreements and a transition services agreement, among the parties and their affiliates, and (iv) other customary closing conditions.
The Gulf Power SPA may be terminated by either Southern Company or 700 Universe, LLC under certain circumstances, including if the sale is not consummated by June 28, 2019 (subject to extension to December 31, 2019, if all of the conditions to closing, other than the conditions related to obtaining regulatory approvals, have been satisfied). The Gulf Power SPA further provides that, upon the termination thereof, (i) under certain specified circumstances, 700 Universe, LLC will be required to pay Southern Company a termination fee of $100 million or $200 million (such amount depending on the specific circumstances of such termination) and (ii) upon certain other specified circumstances Southern Company will be required to pay 700 Universe, LLC a termination fee of $100 million.
The sale of Gulf Power is expected to occur in the first half of 2019.totaled $2.5 billion pre-tax ($1.3 billion after tax). The assets and liabilities of Gulf Power arewere classified as assets held for sale and liabilities held for sale on Southern Company's balance sheet as of June 30,December 31, 2018. See "Assets Held
Management has started the process to sell one of PowerSecure's business units; therefore, the related assets and liabilities have been reclassified as held for Sale" below for additional information.sale on Southern Company's balance sheet as of March 31, 2019. The ultimate outcome of this matter cannot be determined at this time.time; however, any related gain or loss on the potential sale is not expected to have a material effect on Southern Company's financial statements.
See "Assets Held for Sale" herein for additional information.
Southern Power
See Note 11 to the financial statements of Southern Power and Note 12 to the financial statements of Southern Company under "Southern Power" in Item 8 of the Form 10-K for additional information.
Acquisitions During the Six Months Ended June 30, 2018
During the six months ended June 30, 2018, one of Southern Power's wholly-owned subsidiaries acquired and completed construction of the Gaskell West 1 solar facility. Acquisition-related costs were expensed as incurred and were not material.

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

Project FacilityResourceSeller; Acquisition Date
Approximate Nameplate Capacity (MW)
LocationSouthern Power Percentage OwnershipActual CODPPA Contract Period
Gaskell West 1SolarRecurrent Energy Development Holdings, LLC January 26, 201820Kern County, CA100% of Class B(*)March 201820 years
(*)Southern Power owns 100% of the class B membership interests under a tax equity partnership agreement.
The Gaskell West 1 facility did not have operating revenues or activities prior to completion of construction and the assets being placed in service during March 2018.
Construction Projects Completed and in Progress
During the sixthree months ended June 30, 2018,March 31, 2019, Southern Power started or continued construction of the projects set forth in the table below. Total aggregate construction costs, excluding the acquisition costs, are expected to be between $520$575 million and $590$640 million for the Cactus Flats,Plant Mankato expansion and Wild Horsethe Wildhorse Mountain and Reading facilities. At June 30, 2018,March 31, 2019, total costs of construction costsincurred for these projects were $347 million and are included in CWIP, related to these projects totaled $353 million.except for the Plant Mankato expansion, which is included in assets held for sale in the financial statements. The ultimate outcome of these matters cannot be determined at this time.
Project FacilityResource
Approximate Nameplate Capacity (MW)
LocationActual/Expected CODPPA Contract Period
Projects Under Construction as of June 30, 2018
Cactus FlatsMankato expansion(a)
Wind148Concho County, TXJuly 201812-15 years
MankatoNatural Gas345385Mankato, MNFirst halfMay 201920 years
Wild HorseWildhorse Mountain(b)
Wind100Pushmataha County, OKFourth quarter 201920 years
Reading(c)
Wind200Osage and Lyon Counties, KSSecond quarter 202012 years
(a)
In July 2017,November 2018, Southern Power purchased 100%entered into an agreement to sell all of the Cactus Flats facilityits equity interests in Plant Mankato, including this expansion currently under construction. This transaction is subject to FERC and commenced construction. Subsequent to June 30, 2018, the facility was placed in servicestate commission approvals and Southern Power expectsis expected to close on a tax equity partnership agreement, which would result in Southern Power owning 100%mid-2019. The ultimate outcome of the class B membership interests.this matter cannot be determined at this time. See "Sales of Natural Gas and Biomass Plants" below.
(b)
In May 2018, Southern Power purchased 100% of the Wild HorseWildhorse Mountain facility and commenced construction.facility. Southern Power may enter into a tax equity partnership, agreement, in which case it would then own 100% of the class B membership interests. The ultimate outcome of this matter cannot be determined at this time.
(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. described below. Southern Power may enter into a tax equity partnership, in which case it would then own 100% of the class B membership interests. The ultimate outcome of this matter cannot be determined at this time.
Development Projects
During 2017, as part of its renewable development strategy, Southern Power purchased wind turbine equipment from Siemens Gamesa Renewable Energy Inc. and Vestas-American Wind Technology, Inc. to be used for various development and construction projects. Any wind projects reaching commercial operation by 2021 are expected to qualify for 80% PTCs.
During 2016, Southern Power entered into a joint development agreement with Renewable Energy Systems Americas, Inc. to develop and construct wind projects. In addition, in 2016, Southern Power purchased wind turbine equipment from Siemens Wind Power, Inc. and Vestas-American Wind Technology, Inc. to be used for construction of the facilities. Any wind projects reaching commercial operation by 2020 are expected to qualify for 100% PTCs.
In response to the previously disclosed decrease of planned expenditures for plant acquisitions and placeholder growth, Southern Power continues to evaluate and refine the deployment of the wind turbine equipment purchased in 2016 and 2017 to potential joint development and construction projects andas well as the amount of MW capacity to be constructed. WhileDuring the expectation is that the majoritythree months ended March 31, 2019, approximately $53 million of equipment was marketed for sale and, subsequent to March 31, 2019, was sold. At March 31, 2019, the equipment will be deployed in a manner to qualifywas classified as held for the 100%

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(UNAUDITED)

sale on Southern Company's and 80% PTCs, Southern Power may consider other strategies, such as selling equipment or interests in projects.Power's balance sheets. See "Assets Held for Sale" herein for additional information.
The ultimate outcome of these matters cannot be determined at this time.

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

SaleSales of Solar Facility Interests
In May 2018, Southern Power sold a 33% equity interest in SPSH, a newly-formed limited partnership indirectly owning substantially all of Southern Power's solar facilities, to Global Atlantic Financial Group Limited (Global Atlantic) for approximately $1.2 billion, subject to customary working capital adjustments. The proceeds were used to repay $770 million of existing indebtedness, to return capital of $250 million to Southern Company,Natural Gas and for other general corporate purposes, including working capital. Since Southern Power retains control of the limited partnership through its wholly-owned general partner, the sale was recorded as an equity transaction and Southern Power will continue to consolidate the results of SPSH. On the date of the transaction, the noncontrolling interest was increased by $511 million to reflect 33% of the carrying value of the partnership. This difference, partially offset by the tax impact and other related transaction charges, also resulted in a $407 million decrease to Southern Power's common stockholder's equity.
Sale of FloridaBiomass Plants
In MayNovember 2018, Southern Power entered into an equity interest purchase agreement with NextEra EnergyNorthern States Power to sell all of its equity interests in Plant Mankato (including the Florida Plants,385-MW expansion currently under construction) for an aggregate purchase price of $195 million,approximately $650 million. The completion of the disposition is subject to the expansion unit reaching commercial operation as well as various other customary conditions to closing, including working capital and timing adjustments.
The sale This transaction is subject to certain closingFERC and timing conditions and approvals, including, but not limited to, the expiration or termination of the waiting period under the HSR Act and approval by the FERC. The ultimate purchase price will decrease $110,000 per day for each day after December 31, 2018 through the closing of the transaction. Conversely, the ultimate purchase price will increase $110,000 per day for each day the closing occurs prior to December 31, 2018. The transaction is currently expected to occur in the first half of 2019. As a result of this pending transaction, Southern Power recorded an asset impairment charge of approximately $119 million ($89 million after tax) in the second quarter 2018.state commission approvals. The assets and liabilities of the Florida PlantsPlant 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,March 31, 2019 and December 31, 2018. See "Assets Held for Sale" belowherein for additional information. The
On April 17, 2019, Southern Power entered into an agreement to sell all of its equity interests in the Nacogdoches biomass-fueled facility to Austin Energy for an aggregate purchase price of $460 million, subject to customary closing conditions and working capital adjustments.
Each of these sales is expected to close in mid-2019; however, the ultimate outcome of this matterthese matters cannot be determined at this time.
Assets Subject to LienEquity Method Investments
Under the termsThe carrying amounts of the PPASouthern Company Gas' equity method investments as of March 31, 2019 and the expansion PPADecember 31, 2018 and related income from those investments for the Mankato project, approximately $475 millionthree-month periods ended March 31, 2019 and 2018 were as follows:
Investment BalanceMarch 31, 2019December 31, 2018
 (in millions)
SNG$1,262
$1,261
Atlantic Coast Pipeline96
83
PennEast Pipeline75
71
Other124
123
Total$1,557
$1,538
Earnings from Equity Method InvestmentsThree Months Ended
March 31, 2019
Three Months
Ended
March 31, 2018
 (in millions)
SNG$42
$39
Atlantic Coast Pipeline3
1
PennEast Pipeline2
1
Other1
1
Total$48
$42
SNG
Selected financial information of assets, primarily related to property, plant,SNG for the three months ended March 31, 2019 and equipment, are subject to lien at June 30, 2018.2018 is as follows:
Income Statement Information
Three Months Ended
March 31, 2019
Three Months
Ended
March 31, 2018
 (in millions)
Revenues$166
$160
Operating income106
99
Net income84
78
Southern Company Gas(F) FINANCING
SaleBank 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 Pivotal Home Solutions
On June 4, 2018, Southern Company Gas completed the stock sale of Pivotal Home Solutions to American Water Enterprises LLC for a total cash purchase price of $358 million and an additional $6 million for working capital. This disposition resulted in a net loss of $76 million, which included $40 million of income tax expense. In contemplationvariable rate revenue bonds of the transaction, a goodwill impairment chargetraditional electric operating companies outstanding requiring liquidity support as of $42 millionMarch 31, 2019 was recorded during the first quarter 2018. The after-tax loss included income tax expense on goodwill not deductible for tax purposes and for which a deferred tax liability had not been recorded previously. Additionally, this disposition is subject to a final working capital adjustment that may impact the cash proceeds from disposition, but not the loss recorded. Southern Company Gas and American Water Enterprises LLC entered into a transition services agreement whereby Southern Company Gas will provide certain administrative and operational services through no later than February 3, 2019.
Sale of Elizabethtown Gas and Elkton Gas
On July 1, 2018, a Southern Company Gas subsidiary, Pivotal Utility Holdings, completed the sales of the assets of two of its natural gas distribution utilities, Elizabethtown Gas and Elkton Gas, to South Jersey Industries, Inc. for a total cash purchase price of $1.7approximately $1.4 billion and an additional $40 million for working capital. This disposition resulted in an estimated pre-tax gain(comprised of approximately $235$854 million and an after-tax gainat Alabama Power, $550 million at Georgia

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

Power, and $40 million at Mississippi Power). In addition, at March 31, 2019, the traditional electric operating companies had approximately $432 million (comprised of approximately $87 million at Alabama Power and $345 million at Georgia Power) of revenue bonds outstanding that were required to be remarketed within the next 12 months. Subsequent to March 31, 2019, Georgia Power purchased and held approximately $115 million of outstanding pollution control revenue bonds required to be remarketed. 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 March 31, 2019:
 Expires  
Company201920202022 Total 
Unused(d)
 (in millions)
Southern Company(a)
$
$
$2,000
 $2,000
 $1,999
Alabama Power33
500
800
 1,333
 1,333
Georgia Power

1,750
 1,750
 1,736
Mississippi Power100


 100
 100
Southern Power(b)


750
 750
 741
Southern Company Gas(c)


1,900
 1,900
 1,895
Other30


 30
 30
Southern Company Consolidated$163
$500
$7,200
 $7,863
 $7,834
(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$24 million was unused at March 31, 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 $1.4 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.
(d)Amounts used are for letters of credit.
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 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 March 31, 2019, Georgia Power had a total of $3.46 billion of borrowings outstanding under the FFB Credit Facilities.

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(UNAUDITED)

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.
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.

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(UNAUDITED)

Financing Activities
The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first three months of 2019:
CompanySenior 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 Power200
 
 
 
 
Georgia Power
 343
 108
 835
 2
Mississippi Power
 43
 
 
 
Other
 
 
 
 19
Southern Company Consolidated$2,300
 $386
 $108
 $835
 $21
(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.
Subsequent to March 31, 2019, Georgia Power purchased and held the following pollution control revenue bonds, which may be reoffered to the public at a later date:
$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.
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, that previously had been purchased and held by Mississippi Power.
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 March 31, 2019Three Months Ended March 31, 2018
 (in millions)
As reported shares1,038
1,011
Effect of stock-based compensation7
5
Diluted shares1,045
1,016
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 months ended March 31, 2019 and an immaterial amount of such awards was not included for the three months ended March 31, 2018.

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(UNAUDITED)

(G) INCOME TAXES
See Note 10 to the financial statements in Item 8 of the Form 10-K for additional tax information.
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 39.8% for the three months ended March 31, 2019 compared to 10.8% for the corresponding period in 2018. The effective tax rate increase was primarily due to the tax impact from the sale of Gulf Power. See Note (K) for additional information.
Alabama Power
Alabama Power's effective tax rate was 21.9% for the three months ended March 31, 2019 compared to 26.3% for the corresponding period in 2018. The effective tax rate decrease was primarily due to the application in 2018 of the accounting order approved by the Alabama PSC in May 2018 related to the Tax Reform Legislation. 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.
Mississippi Power
Mississippi Power's effective tax rate was 15.5% for the three months ended March 31, 2019 compared to a benefit rate of (34.7)% for the corresponding period in 2018. The effective tax rate increase was primarily due to lower estimated losses on the Kemper IGCC in 2019, partially offset by 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.
Southern Power
Southern Power's effective tax benefit rate was (49.8)% for the three months ended March 31, 2019 compared to (647.0)% for the corresponding period in 2018. The effective tax benefit rate decrease was primarily due to changes in state apportionment rates following the reorganization of Southern Power's legal entities that own and operate certain solar facilities and a reduction of tax benefits from wind PTCs primarily as a result of the sale of a noncontrolling tax equity interest in SP Wind.
Southern Company Gas
Southern Company Gas' effective tax rate was 22.3% for the three months ended March 31, 2019 compared to 27.2% for the corresponding period in 2018. This decrease was primarily related to tax impacts of the goodwill impairment charge recorded in the thirdfirst quarter 2018. The after-tax gain included income tax expense on goodwill not deductible for tax purposes2018 and for which a deferred tax liability had not been recorded previously. Additionally, this disposition is subject to a final working capital adjustment that may impact the cash proceeds from disposition, but not the gain that will be recordedan increase in the third quarter 2018.flowback of excess deferred income taxes in 2019 primarily at Atlanta Gas Light as previously authorized by the Georgia PSC. See Note 2 to the financial statements under "Southern Company Gas – Rate Proceedings" 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

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(UNAUDITED)

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 South Jersey Industries, Inc. enteredlife 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.
Components of the net periodic benefit costs for the three months ended March 31, 2019 and 2018 are presented in the following tables.
Three Months Ended
March 31, 2019
Southern
Company
 
Alabama
Power
 
Georgia
Power
 
Mississippi
Power
 Southern Power Southern Company Gas
 (in millions)
Pension Plans
Service cost$73
 $17
 $19
 $3
 $2
 $6
Interest cost123
 28
 39
 6
 1
 9
Expected return on plan assets(221) (51) (73) (10) (2) (15)
Amortization:           
Prior service costs
 
 
 
 
 (1)
Regulatory asset
 
 
 
 
 3
Net (gain)/loss30
 9
 11
 1
 
 1
Net periodic pension cost (income)$5
 $3
 $(4) $
 $1
 $3
Postretirement Benefits
Service cost$5
 $1
 $1
 $
 $
 $1
Interest cost17
 4
 7
 1
 
 2
Expected return on plan assets(16) (6) (6) 
 
 (2)
Amortization:           
Prior service costs1
 1
 
 
 
 
Regulatory asset
 
 
 
 
 2
Net (gain)/loss(1) 
 
 
 
 (1)
Net periodic postretirement benefit cost$6
 $
 $2
 $1
 $
 $2

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(UNAUDITED)

Three Months Ended
March 31, 2018
Southern
Company
 
Alabama
Power
 
Georgia
Power
 
Mississippi
Power
 Southern Power Southern Company Gas
 (in millions)
Pension Plans
Service cost$90

$19

$22

$4

$2

$8
Interest cost116

25

35

5

1

10
Expected return on plan assets(236)
(51)
(74)
(10)
(3)
(18)
Amortization:           
Prior service costs1









(1)
Regulatory asset
 
 
 
 
 3
Net (gain)/loss53

14

17

3

1

3
Net periodic pension cost (income)$24

$7

$

$2

$1

$5
Postretirement Benefits
Service cost$6
 $1
 $2
 $
 $
 $1
Interest cost19
 4
 7
 1
 
 2
Expected return on plan assets(17) (6) (6) 
 
 (2)
Amortization:           
Prior service costs2
 1
 
 
 
 
Regulatory asset
 
 
 
 
 1
Net (gain)/loss3
 
 2
 
 
 
Net periodic postretirement benefit cost$13
 $
 $5
 $1
 $
 $2

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

(I) FAIR VALUE MEASUREMENTS
As of March 31, 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 March 31, 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)(b)
$322
 $128
 $4
 $
 $454
Foreign currency derivatives
 38
 
 
 38
Investments in trusts:(c)(d)
         
Domestic equity682
 120
 
 
 802
Foreign equity60
 195
 
 
 255
U.S. Treasury and government agency securities
 283
 
 
 283
Municipal bonds
 73
 
 
 73
Pooled funds – fixed income
 14
 
 
 14
Corporate bonds24
 298
 
 
 322
Mortgage and asset backed securities
 72
 
 
 72
Private equity
 
 
 48
 48
Cash and cash equivalents1
 
 
 
 1
Other28
 4
 
 
 32
Cash equivalents907
 3
 
 
 910
Other investments9
 14
 
 
 23
Total$2,033
 $1,242
 $4
 $48
 $3,327
Liabilities:         
Energy-related derivatives(a)(b)
$466
 $106
 $23
 $
 $595
Interest rate derivatives
 35
 
 
 35
Foreign currency derivatives
 24
 
 
 24
Contingent consideration
 
 21
 
 21
Total$466
 $165
 $44
 $
 $675
          

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

 Fair Value Measurements Using:  
As of March 31, 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:(c)
        

Domestic equity446
 108
 
 
 554
Foreign equity60
 57
 
 
 117
U.S. Treasury and government agency securities
 18
 
 
 18
Municipal bonds
 1
 
 
 1
Corporate bonds24
 139
 
 
 163
Mortgage and asset backed securities
 24
 
 
 24
Private equity
 
 
 48
 48
Other5
 
 
 
 5
Cash equivalents569
 3
 
 
 572
Other investments
 14
 
 
 14
Total$1,104
 $370
 $
 $48
 $1,522
Liabilities:         
Energy-related derivatives$
 $7
 $
 $
 $7
          
Georgia Power         
Assets:         
Energy-related derivatives$
 $9
 $
 $
 $9
Nuclear decommissioning trusts:(c)(d)
         
Domestic equity236
 1
 
 
 237
Foreign equity
 134
 
 
 134
U.S. Treasury and government agency securities
 265
 
 
 265
Municipal bonds
 72
 
 
 72
Corporate bonds
 160
 
 
 160
Mortgage and asset backed securities
 47
 
 
 47
Other23
 4
 
 
 27
Total$259
 $692
 $
 $
 $951
Liabilities:         
Energy-related derivatives$
 $16
 $
 $
 $16
Interest rate derivatives
 2
 
 
 2
Total$
 $18
 $
 $
 $18
          

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

 Fair Value Measurements Using:  
As of March 31, 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 equivalents202
 
 
 
 202
Total$202
 $3
 $
 $
 $205
Liabilities:         
Energy-related derivatives$
 $6
 $
 $
 $6
          
Southern Power         
Assets:         
Energy-related derivatives$
 $1
 $
 $
 $1
Foreign currency derivatives
 38
 
 

38
Cash equivalents10
 
 
 
 10
Total$10
 $39
 $
 $
 $49
Liabilities:         
Energy-related derivatives$
 $3
 $
 $
 $3
Foreign currency derivatives
 24
 
 
 24
Contingent consideration
 
 21
 
 21
Total$

$27

$21

$

$48
          
Southern Company Gas         
Assets:         
Energy-related derivatives(a)(b)
$322
 $108
 $4
 $
 $434
Non-qualified deferred compensation trusts:         
Domestic equity
 11
 
 
 11
Foreign equity
 4
 
 
 4
Pooled funds – fixed income
 14
 
 
 14
Cash equivalents1
 
 
 
 1
Cash equivalents13
 
 
 
 13
Total$336

$137

$4

$

$477
Liabilities:         
Energy-related derivatives(a)(b)
$466
 $73
 $23
 $
 $562
(a)
Energy-related derivatives exclude $11 million associated with premiums and certain weather derivatives accounted for based on intrinsic value rather than fair value.
(b)
Energy-related derivatives exclude cash collateral of $190 million.
(c)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.
(d)
Includes investment securities pledged to creditors and collateral received and excludes payables related to the securities lending program. As of March 31, 2019, approximately $72 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.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

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 and dividends and excluding the funds' expenses, increased for the three months ended March 31, 2019 and decreased for the three months ended March 31, 2018 by the amounts shown in the table below. 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
March 31, 2019
Three Months
Ended
March 31, 2018
 (in millions)
Southern Company$152
$(11)
Alabama Power87
(5)
Georgia Power65
(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 transition services agreementsproprietary 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.

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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.
As of March 31, 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 $48 million and unfunded commitments related to the private equity investments totaled $49 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 March 31, 2019, other financial instruments for which the carrying amount did not equal fair value were as follows:
 
Southern
Company
Alabama PowerGeorgia PowerMississippi PowerSouthern Power
Southern Company Gas(*)
 (in millions)
Long-term debt, including securities due within one year:    
Carrying amount$42,535
$7,921
$10,910
$1,619
$4,995
$5,928
Fair value43,910
8,424
11,249
1,619
5,131
6,176
(*)The long-term debt of Southern Company Gas is recorded at amortized cost, including the fair value adjustments at the effective date of the Merger. 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 March 31, 2019, the fair value of Southern Company Gas' Level 3 physical natural gas forward contracts was $19 million. Since commodity contracts classified as Level 3 typically include a combination of observable and unobservable components, the changes in fair value may include amounts due in part to observable market factors, or changes to assumptions on the unobservable components. The following table includes transfers to Level 3, which represent the fair value of Southern Company Gas' commodity derivative contracts that include a significant unobservable component for the first time during the period.
 Three Months Ended March 31, 2019
 (in millions)
Beginning balance$
Transfers to Level 3(30)
Changes in fair value11
Ending balance$(19)
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

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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 $0.07 to $1.15 per mmBtu). Forward price increases (decreases) as of March 31, 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 willare 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 March 31, 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(*)
538 2022 2029
Alabama Power72 2022 
Georgia Power153 2022 
Mississippi Power61 2022 
Southern Power9 2020 
Southern Company Gas(*)
243 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 3.8 billion mmBtu and short natural gas positions of 3.6 billion mmBtu as of March 31, 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 40 million mmBtu for Southern Company, which includes 6 million mmBtu for Alabama Power, 12 million mmBtu for Georgia Power, 5 million mmBtu for Mississippi Power, and 13 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 next 12-month period ending March 31, 2020 are immaterial for all registrants.
Interest Rate Derivatives
Southern Company and certain administrativesubsidiaries 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

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hedges where the derivatives' fair value gains or losses are recorded in OCI and operational servicesare reclassified into earnings at the same time and presented on the same income statement line item as the earnings effect of the hedged transactions. Derivatives related to existing fixed rate securities are accounted for as fair value hedges, where the derivatives' fair value gains or losses and hedged items' fair value gains or losses are both recorded directly to earnings on the same income statement line item. Fair value gains or losses on derivatives that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.
At March 31, 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 March 31, 2019
 (in millions)     (in millions)
Fair Value Hedges of Existing Debt      
Southern Company(*)
$300
 2.75%3-month LIBOR+0.92%June 2020 $(3)
Southern Company(*)
1,500
 2.35%1-month LIBOR+0.87%July 2021 (30)
Georgia Power200
 4.25%3-month LIBOR+2.46%December 2019 (2)
Southern Company Consolidated$2,000
     $(35)
(*)Represents the Southern Company parent entity.
The estimated pre-tax gains (losses) related to interest rate derivatives expected to be reclassified from accumulated OCI to interest expense for the next 12-month period ending March 31, 2020 are $(19) 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, 2037 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.
At March 31, 2019, the following foreign currency derivatives were outstanding:
 Pay NotionalPay RateReceive NotionalReceive RateHedge
Maturity Date
Fair Value Gain (Loss) at March 31, 2019
 (in millions) (in millions)  (in millions)
Cash Flow Hedges of Existing Debt     
Southern Power$677
2.95%600
1.00%June 2022$2
Southern Power564
3.78%500
1.85%June 202611
Total$1,241
 1,100
  $13

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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 next 12-month period ending March 31, 2020 are $(24) 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 March 31, 2019As of December 31, 2018
Derivative Category and Balance Sheet LocationAssetsLiabilitiesAssetsLiabilities
 (in millions)(in millions)
Southern Company    
Derivatives designated as hedging instruments for regulatory purposes    
Energy-related derivatives:    
Other current assets/Other current liabilities$12
$10
$8
$23
Other deferred charges and assets/Other deferred credits and liabilities11
21
9
26
Assets held for sale, current/Liabilities held for sale, current


6
Total derivatives designated as hedging instruments for regulatory purposes$23
$31
$17
$55
Derivatives designated as hedging instruments in cash flow and fair value hedges    
Energy-related derivatives:    
Other current assets/Other current liabilities$1
$3
$3
$7
Other deferred charges and assets/Other deferred credits and liabilities
1
1
2
Interest rate derivatives:    
Other current assets/Other current liabilities
20

19
Other deferred charges and assets/Other deferred credits and liabilities
15

30
Foreign currency derivatives:    
Other current assets/Other current liabilities
24

23
Other deferred charges and assets/Other deferred credits and liabilities38

75

Total derivatives designated as hedging instruments in cash flow and fair value hedges$39
$63
$79
$81
Derivatives not designated as hedging instruments    
Energy-related derivatives:    
Other current assets/Other current liabilities$259
$291
$561
$575
Other deferred charges and assets/Other deferred credits and liabilities171
269
180
325
Total derivatives not designated as hedging instruments$430
$560
$741
$900
Gross amounts recognized$492
$654
$837
$1,036
Gross amounts offset(a)
$(333)$(523)$(524)$(801)
Net amounts recognized in the Balance Sheets(b)
$159
$131
$313
$235
     

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 As of March 31, 2019As of December 31, 2018
Derivative Category and Balance Sheet LocationAssetsLiabilitiesAssetsLiabilities
 (in millions)(in millions)
Alabama Power    
Derivatives designated as hedging instruments for regulatory purposes    
Energy-related derivatives:    
Other current assets/Other current liabilities$3
$2
$3
$4
Other deferred charges and assets/Other deferred credits and liabilities3
5
3
6
Total derivatives designated as hedging instruments for regulatory purposes$6
$7
$6
$10
Gross amounts recognized$6
$7
$6
$10
Gross amounts offset$(5)$(5)$(4)$(4)
Net amounts recognized in the Balance Sheets$1
$2
$2
$6
     
Georgia Power    
Derivatives designated as hedging instruments for regulatory purposes    
Energy-related derivatives:    
Other current assets/Other current liabilities$4
$5
$2
$8
Other deferred charges and assets/Other deferred credits and liabilities5
11
4
13
Total derivatives designated as hedging instruments for regulatory purposes$9
$16
$6
$21
Derivatives designated as hedging instruments in cash flow and fair value hedges    
Interest rate derivatives:    
Other current assets/Other current liabilities$
$2
$
$2
Total derivatives designated as hedging instruments in cash flow and fair value hedges$
$2
$
$2
Gross amounts recognized$9
$18
$6
$23
Gross amounts offset$(8)$(8)$(6)$(6)
Net amounts recognized in the Balance Sheets$1
$10
$
$17
     

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 As of March 31, 2019As of December 31, 2018
Derivative Category and Balance Sheet LocationAssetsLiabilitiesAssetsLiabilities
 (in millions)(in millions)
Mississippi Power    
Derivatives designated as hedging instruments for regulatory purposes    
Energy-related derivatives:    
Other current assets/Other current liabilities$2
$2
$1
$3
Other deferred charges and assets/Other deferred credits and liabilities1
4
2
6
Total derivatives designated as hedging instruments for regulatory purposes$3
$6
$3
$9
Gross amounts recognized$3
$6
$3
$9
Gross amounts offset$(3)$(3)$(2)$(2)
Net amounts recognized in the Balance Sheets$
$3
$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
$2
$3
$6
Other deferred charges and assets/Other deferred credits and liabilities
1
1
2
Foreign currency derivatives:    
Other current assets/Other current liabilities
24

23
Other deferred charges and assets/Other deferred credits and liabilities38

75

Total derivatives designated as hedging instruments in cash flow and fair value hedges$39
$27
$79
$31
Gross amounts recognized$39
$27
$79
$31
Gross amounts offset$(1)$(1)$(3)$(3)
Net amounts recognized in the Balance Sheets$38
$26
$76
$28
     
Southern Company Gas    
Derivatives designated as hedging instruments for regulatory purposes    
Energy-related derivatives:    
Assets from risk management activities/Liabilities from risk management activities-current$3
$1
$2
$8
Other deferred charges and assets/Other deferred credits and liabilities1


1
Total derivatives designated as hedging instruments for regulatory purposes$4
$1
$2
$9
Derivatives designated as hedging instruments in cash flow and fair value hedges    
Energy-related derivatives:    
Assets from risk management activities/Liabilities from risk management activities-current$
$1
$
$1
Total derivatives designated as hedging instruments in cash flow and fair value hedges$
$1
$
$1

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 As of March 31, 2019As of December 31, 2018
Derivative Category and Balance Sheet LocationAssetsLiabilitiesAssetsLiabilities
 (in millions)(in millions)
Derivatives not designated as hedging instruments    
Energy-related derivatives:    
Assets from risk management activities/Liabilities from risk management activities-current$259
$291
$559
$574
Other deferred charges and assets/Other deferred credits and liabilities171
269
180
325
Total derivatives not designated as hedging instruments$430
$560
$739
$899
Gross amounts of recognized$434
$562
$741
$909
Gross amounts offset(a)
$(316)$(506)$(508)$(785)
Net amounts recognized in the Balance Sheets(b)
$118
$56
$233
$124
(a)Gross amounts offset include cash collateral held on deposit in broker margin accounts of $190 million and $277 million as of March 31, 2019 and December 31, 2018, respectively.
(b)Net amounts of derivative instruments outstanding exclude premium and intrinsic value associated with weather derivatives of $11 million and $8 million as of March 31, 2019 and December 31, 2018, respectively.
At March 31, 2019 and December 31, 2018, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred were as follows:
Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at March 31, 2019
Derivative Category and Balance Sheet
Location
Southern
Company(*)
Alabama
Power
Georgia
Power
Mississippi
Power
Southern Company Gas(*)
 (in millions)
Energy-related derivatives:     
Other regulatory assets, current$(5)$(1)$(2)$(1)$(1)
Other regulatory assets, deferred(11)(2)(6)(3)
Other regulatory liabilities, current7
1
1
1
4
Total energy-related derivative gains (losses)$(9)$(2)$(7)$(3)$3
(*)Fair value gains and losses recorded in regulatory assets and liabilities include cash collateral held on deposit in broker margin accounts of $2 million at March 31, 2019.
Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at December 31, 2018
Derivative Category and Balance Sheet
Location
Southern
Company
Alabama
Power
Georgia
Power
Mississippi
Power
Southern Company Gas
 (in millions)
Energy-related derivatives:     
Other regulatory assets, current$(19)$(3)$(6)$(2)$(8)
Other regulatory assets, deferred(16)(3)(9)(4)
Assets held for sale, current(6)



Other regulatory liabilities, current1



1
Total energy-related derivative gains (losses)$(40)$(6)$(15)$(6)$(7)

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For the three months ended March 31, 2019 and 2018, the pre-tax effects of cash flow hedge accounting on accumulated OCI were as follows:
Gain (Loss) Recognized in OCI on DerivativeFor the Three Months
Ended March 31,
20192018
 (in millions)
Southern Company  
Energy-related derivatives$
$12
Interest rate derivatives
(2)
Foreign currency derivatives(39)53
Total$(39)$63
Southern Power  
Energy-related derivatives$
$11
Foreign currency derivatives(39)53
Total$(39)$64
For the three months ended March 31, 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.
For the three months ended March 31, 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 RelationshipsFor the Three Months
Ended March 31,
 
 20192018
  (in millions)
 Southern Company  
 Total depreciation and amortization$751
$769
 
Gain (loss) on energy-related cash flow hedges(a)
(3)1
 Total interest expense, net of amounts capitalized(430)(458)
 
Gain (loss) on interest rate cash flow hedges(a)
(5)(5)
 
Gain (loss) on foreign currency cash flow hedges(a)
(6)(5)
 
Gain (loss) on interest rate fair value hedges(b)
14
(24)
 Total other income (expense), net78
60
 
Gain (loss) on foreign currency cash flow hedges(a)(c)
(24)36
 Southern Power  
 Total depreciation and amortization$119
$114
 
Gain (loss) on energy-related cash flow hedges(a)
(3)1
 Total interest expense, net of amounts capitalized(44)(47)
 
Gain (loss) on foreign currency cash flow hedges(a)
(6)(5)
 Total other income (expense), net2
3
 
Gain (loss) on foreign currency cash flow hedges(a)(c)
(24)36
(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.

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For the three months ended March 31, 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 March 31, 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 ItemsAs of March 31, 2019As of December 31, 2018
As of March 31, 2019As of December 31, 2018

(in millions) (in millions)
Southern Company     
Securities due within one year$(499)$(498) $1
$2
Long-term debt(2,065)(2,052) 28
41
      
Georgia Power     
Securities due within one year$(499)$(498) $1
$2
Long-term debt

 

For the three months ended March 31, 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 March 31,
Derivatives in Non-Designated Hedging RelationshipsStatements of Income Location20192018
  (in millions)
Energy-related derivatives:
Natural gas revenues(*)
$33
$(15)
 Cost of natural gas8
2
Total derivatives in non-designated hedging relationships$41
$(13)
(*)Excludes immaterial gains (losses) recorded in natural gas revenues associated with weather derivatives for the three months ended March 31, 2019 and 2018.
For the three months ended March 31, 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 March 31, 2019, the registrants had no latercollateral posted with derivative counterparties to satisfy these arrangements.
For the registrants with interest rate derivatives at March 31, 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 March 31, 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

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(UNAUDITED)

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 March 31, 2019, cash collateral posted in these accounts was immaterial. Southern Company Gas maintains accounts with brokers or the clearing houses of certain exchanges to facilitate financial derivative transactions. Based on the value of the positions in these accounts and the associated margin requirements, Southern Company Gas may be required to deposit cash into these accounts. At March 31, 2019, cash collateral held on deposit in broker margin accounts was $190 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 31, 2020.1, 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 ElizabethtownGulf Power were classified as assets held for sale and liabilities held for sale on Southern Company's balance sheet as of December 31, 2018.
Management has started the process to sell one of PowerSecure's business units; therefore, the related assets and liabilities have been reclassified as held for sale on Southern Company's balance sheet as of March 31, 2019. The ultimate outcome of this matter cannot be determined at this time; however, any related gain or loss on the potential sale is not expected to have a material effect on Southern Company's financial statements.
See "Assets Held for Sale" herein for additional information.
Southern Power
Construction Projects in Progress
During the three months ended March 31, 2019, Southern Power continued construction of the projects set forth in the table below. Total aggregate construction costs, excluding the acquisition costs, are expected to be between $575 million and $640 million for the Plant Mankato expansion and the Wildhorse Mountain and Reading facilities. At March 31, 2019, total costs of construction incurred for these projects were $347 million and are included in CWIP, except for the Plant Mankato expansion, which is included in assets held for sale in the financial statements. The ultimate outcome of these matters cannot be determined at this time.
Project FacilityResource
Approximate Nameplate Capacity (MW)
LocationExpected CODPPA Contract Period
Mankato expansion(a)
Natural Gas385Mankato, MNMay 201920 years
Wildhorse Mountain(b)
Wind100Pushmataha County, OKFourth quarter 201920 years
Reading(c)
Wind200Osage and Lyon Counties, KSSecond quarter 202012 years
(a)
In November 2018, Southern Power entered into an agreement to sell all of its equity interests in Plant Mankato, including this expansion currently under construction. This transaction is subject to FERC and state commission approvals and is expected to close mid-2019. The ultimate outcome of this matter cannot be determined at this time. See "Sales of Natural Gas and Biomass Plants" below.
(b)
In May 2018, Southern Power purchased 100% of the Wildhorse Mountain facility. Southern Power may enter into a tax equity partnership, in which case it would then own 100% of the class B membership interests. The ultimate outcome of this matter cannot be determined at this time.
(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. described below. Southern Power may enter into a tax equity partnership, in which case it would then own 100% of the class B membership interests. The ultimate outcome of this matter cannot be determined at this time.
Development Projects
Southern Power continues to evaluate and refine the deployment of the 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 three months ended March 31, 2019, approximately $53 million of equipment was marketed for sale and, subsequent to March 31, 2019, was sold. At March 31, 2019, the equipment was classified as held for

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sale on Southern Company's and Southern Power's balance sheets. See "Assets Held for Sale" herein for additional information.
The ultimate outcome of these matters cannot be determined at this time.
Sales of Natural Gas and Elkton GasBiomass Plants
In November 2018, Southern Power entered into an agreement with Northern States Power to sell all of its equity interests in Plant Mankato (including the 385-MW expansion currently under construction) for an aggregate purchase price of approximately $650 million. The completion of the disposition is subject to the expansion unit reaching commercial operation as well as various other customary conditions to closing, including working capital and timing adjustments. This transaction is subject to FERC and state commission approvals. 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 Company Gas'Power's balance sheets at June 30,as of March 31, 2019 and December 31, 2018. See "Assets Held for Sale" belowherein for additional information.
SaleOn April 17, 2019, Southern Power entered into an agreement to sell all of Florida City Gas
On July 29, 2018, Southern Company Gas and its wholly-owned direct subsidiary, NUI Corporation, completedequity interests in the stock sale of Pivotal Utility Holdings, which primarily consisted of Florida City Gas,Nacogdoches biomass-fueled facility to NextEraAustin Energy for a total cashan aggregate purchase price of $530$460 million, (less $3 million of indebtedness assumed at closing for customer deposits) and an additional $60 million for cash and other working capital. This disposition resulted in an estimated pre-tax gain of approximately $126 million and an after-tax gain of approximately $4 million, which will be recorded in the third quarter 2018. The after-tax gain included income tax expense on goodwill not deductible for tax purposes and for which a deferred tax liability had not been recorded previously. Additionally, this disposition is subject to a finalcustomary closing conditions and working capital adjustment that may impact the cash proceeds from disposition, but not the gain that will be recorded in the third quarter 2018. Southern Company Gas and NextEra Energy entered into a transition services agreement whereby Southern Company Gas will provide certain administrative and operational services through no later than July 29, 2020. The assets and liabilities of Florida City Gas are classified as assets held for sale and liabilities held for sale on Southern Company's and Southern Company Gas' balance sheets at June 30, 2018. See "Assets Held for Sale" below for additional information.adjustments.
Assets Held for Sale
As discussed above, Southern Company, Southern Power, and Southern Company Gas each have assets and liabilities held for sale on their balance sheets at June 30, 2018. Assets and liabilities held for sale have been classified separately on each company's balance sheet at the lower of carrying value or fair value less costs to sell at the time the criteria for held-for-sale classification were met. For assets and liabilities held for sale recorded at fair value on a nonrecurring basis, the fair value of assets held for sale is based primarily on unobservable inputs (Level 3), which includes the agreed upon sales prices in executed sales agreements.
Upon classification as held for sale in May 2018, Southern Power ceased recognizing depreciation on the Florida Plants' property, plant, and equipment to be sold. Since the depreciation of the assets to be sold in the Gulf Power transaction continues to be reflected in customer rates and will be reflected in the carryover basis of the assets when sold, Southern Company will continue to record depreciation on those assets through the date the transaction closes. Likewise, since the depreciation of the assets sold in the Elizabethtown Gas, Elkton Gas, and Florida City Gas transactions continued to be reflected in customer rates and was reflected in the carryover basis of the assets when sold, Southern Company Gas continued to record depreciation on those assets through the respective date that each transaction closed.

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

The following table provides each company's major classes of assets and liabilities classified as held for sale at June 30, 2018:
 Southern Company
Southern
Power
Southern Company Gas
 (in millions)
Assets Held for Sale:   
Current assets$487
$17
$81
Total property, plant, and equipment5,462
168
1,408
Goodwill and other intangible assets668

668
Other non-current assets705
15
141
Total Assets Held for Sale$7,322
$200
$2,298
    
Liabilities Held for Sale:   
Current liabilities$354
$2
$61
Long-term debt1,285


Accumulated deferred income taxes566

26
Other non-current liabilities1,334

325
Total Liabilities Held for Sale$3,539
$2
$412
Southern Company, Southern Power, and Southern Company Gas each concluded that the saleEach of these assets, both individually and combined, did not represent a strategic shift in operations that has, orsales is expected to have, a major effect on its operations and financial results; therefore, noneclose in mid-2019; however, the ultimate outcome of these assets held for sale have been classified as discontinued operations for any of the periods presented.matters cannot be determined at this time.
Gulf Power and the Florida Plants represent individually significant components of Southern Company and Southern Power, respectively; therefore, pre-tax profit for these components for the three and six months ended June 30, 2018 and 2017 is presented below:
 For the Three Months
Ended June 30,
 For the Six Months
Ended June 30,
20182017 20182017
 (in millions) (in millions)
Earnings before income taxes:     
Gulf Power$31
$61
 $87
$95
Southern Power's Florida Plants(*)
$14
$11
 $24
$20
(*)Excludes any allocation of interest from Southern Power's corporate debt.

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

(K)VARIABLE INTEREST ENTITY AND EQUITY METHOD INVESTMENTS
Southern Power
In May 2018, Southern Power sold a 33% equity interest in SPSH to Global Atlantic. See Note (J) under "Southern Power" for additional information. A wholly-owned subsidiary of Southern Power is the general partner and holds a 1% ownership interest in SPSH and another wholly-owned subsidiary of Southern Power owns the remaining 66% ownership in SPSH. SPSH is a variable interest entity (VIE) because the arrangement is structured as a limited partnership and the 33% limited partner does not have substantive kick-out rights against the general partner. Southern Power previously consolidated SPSH and will continue to do so as the primary beneficiary of the VIE because it controls the most significant activities of the partnership, including operating and maintaining its assets.
At June 30, 2018, SPSH had total assets of $6.5 billion, total liabilities of $0.1 billion, and noncontrolling interests related to other partners' interests of $1.2 billion. Cash distributions from SPSH are allocated 67% to Southern Power and 33% to Global Atlantic in accordance with their membership interests and the limited partnership agreement.
Transfers and sales of the assets in the VIE are subject to limited partner consent and the liabilities do not have recourse to the general credit of Southern Power. Liabilities consist of customary working capital items and do not include any long-term debt.
Southern Company Gas
See Note 4 to the financial statements of Southern Company Gas in Item 8 of the Form 10-K for additional information.
Equity Method Investments
The carrying amounts of Southern Company Gas' equity method investments as of June 30, 2018March 31, 2019 and December 31, 20172018 and related income from those investments for the three and six-monththree-month periods ended June 30,March 31, 2019 and 2018 and June 30, 2017 were as follows:
Investment BalanceJune 30, 2018December 31, 2017March 31, 2019December 31, 2018
(in millions)(in millions)
SNG$1,258
$1,262
$1,262
$1,261
Atlantic Coast Pipeline56
41
96
83
PennEast Pipeline67
57
75
71
Triton42
42
Pivotal JAX LNG, LLC52
44
Horizon Pipeline31
30
Other1
1
124
123
Total$1,507
$1,477
$1,557
$1,538
Earnings from Equity Method InvestmentsThree Months Ended
March 31, 2019
Three Months
Ended
March 31, 2018
 (in millions)
SNG$42
$39
Atlantic Coast Pipeline3
1
PennEast Pipeline2
1
Other1
1
Total$48
$42
SNG
Selected financial information of SNG for the three months ended March 31, 2019 and 2018 is as follows:
Income Statement Information
Three Months Ended
March 31, 2019
Three Months
Ended
March 31, 2018
 (in millions)
Revenues$166
$160
Operating income106
99
Net income84
78
(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 March 31, 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 March 31, 2019, the traditional electric operating companies had approximately $432 million (comprised of approximately $87 million at Alabama Power and $345 million at Georgia Power) of revenue bonds outstanding that were required to be remarketed within the next 12 months. Subsequent to March 31, 2019, Georgia Power purchased and held approximately $115 million of outstanding pollution control revenue bonds required to be remarketed. 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 March 31, 2019:
 Expires  
Company201920202022 Total 
Unused(d)
 (in millions)
Southern Company(a)
$
$
$2,000
 $2,000
 $1,999
Alabama Power33
500
800
 1,333
 1,333
Georgia Power

1,750
 1,750
 1,736
Mississippi Power100


 100
 100
Southern Power(b)


750
 750
 741
Southern Company Gas(c)


1,900
 1,900
 1,895
Other30


 30
 30
Southern Company Consolidated$163
$500
$7,200
 $7,863
 $7,834
(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 $24 million was unused at March 31, 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 $1.4 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.
(d)Amounts used are for letters of credit.
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 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 March 31, 2019, Georgia Power had a total of $3.46 billion of borrowings outstanding under the FFB Credit Facilities.

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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.
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.

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Financing Activities
The following table outlines the long-term debt financing activities for Southern Company and its subsidiaries for the first three months of 2019:
CompanySenior 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 Power200
 
 
 
 
Georgia Power
 343
 108
 835
 2
Mississippi Power
 43
 
 
 
Other
 
 
 
 19
Southern Company Consolidated$2,300
 $386
 $108
 $835
 $21
(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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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.
Subsequent to March 31, 2019, Georgia Power purchased and held the following pollution control revenue bonds, which may be reoffered to the public at a later date:
$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.
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, that previously had been purchased and held by Mississippi Power.
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 March 31, 2019Three Months Ended March 31, 2018
 (in millions)
As reported shares1,038
1,011
Effect of stock-based compensation7
5
Diluted shares1,045
1,016
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 months ended March 31, 2019 and an immaterial amount of such awards was not included for the three months ended March 31, 2018.

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(G) INCOME TAXES
See Note 10 to the financial statements in Item 8 of the Form 10-K for additional tax information.
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 39.8% for the three months ended March 31, 2019 compared to 10.8% for the corresponding period in 2018. The effective tax rate increase was primarily due to the tax impact from the sale of Gulf Power. See Note (K) for additional information.
Alabama Power
Alabama Power's effective tax rate was 21.9% for the three months ended March 31, 2019 compared to 26.3% for the corresponding period in 2018. The effective tax rate decrease was primarily due to the application in 2018 of the accounting order approved by the Alabama PSC in May 2018 related to the Tax Reform Legislation. 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.
Mississippi Power
Mississippi Power's effective tax rate was 15.5% for the three months ended March 31, 2019 compared to a benefit rate of (34.7)% for the corresponding period in 2018. The effective tax rate increase was primarily due to lower estimated losses on the Kemper IGCC in 2019, partially offset by 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.
Southern Power
Southern Power's effective tax benefit rate was (49.8)% for the three months ended March 31, 2019 compared to (647.0)% for the corresponding period in 2018. The effective tax benefit rate decrease was primarily due to changes in state apportionment rates following the reorganization of Southern Power's legal entities that own and operate certain solar facilities and a reduction of tax benefits from wind PTCs primarily as a result of the sale of a noncontrolling tax equity interest in SP Wind.
Southern Company Gas
Southern Company Gas' effective tax rate was 22.3% for the three months ended March 31, 2019 compared to 27.2% for the corresponding period in 2018. This decrease was primarily related to tax impacts of the goodwill impairment charge recorded in the first quarter 2018 and an increase in the flowback of excess deferred income taxes in 2019 primarily at Atlanta Gas Light as previously authorized by the Georgia PSC. See Note 2 to the financial statements under "Southern Company Gas – Rate Proceedings" 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

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(UNAUDITED)

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.
Components of the net periodic benefit costs for the three months ended March 31, 2019 and 2018 are presented in the following tables.
Three Months Ended
March 31, 2019
Southern
Company
 
Alabama
Power
 
Georgia
Power
 
Mississippi
Power
 Southern Power Southern Company Gas
 (in millions)
Pension Plans
Service cost$73
 $17
 $19
 $3
 $2
 $6
Interest cost123
 28
 39
 6
 1
 9
Expected return on plan assets(221) (51) (73) (10) (2) (15)
Amortization:           
Prior service costs
 
 
 
 
 (1)
Regulatory asset
 
 
 
 
 3
Net (gain)/loss30
 9
 11
 1
 
 1
Net periodic pension cost (income)$5
 $3
 $(4) $
 $1
 $3
Postretirement Benefits
Service cost$5
 $1
 $1
 $
 $
 $1
Interest cost17
 4
 7
 1
 
 2
Expected return on plan assets(16) (6) (6) 
 
 (2)
Amortization:           
Prior service costs1
 1
 
 
 
 
Regulatory asset
 
 
 
 
 2
Net (gain)/loss(1) 
 
 
 
 (1)
Net periodic postretirement benefit cost$6
 $
 $2
 $1
 $
 $2

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(UNAUDITED)

Earnings from Equity Method InvestmentsThree Months Ended
June 30, 2018
Three Months Ended
June 30, 2017
Six Months Ended
June 30, 2018
Six Months
Ended
June 30, 2017
 (in millions)
SNG$27
$24
$66
$58
PennEast Pipeline1
1
2
4
Atlantic Coast Pipeline1
2
3
3
Triton1
2
2
2
Horizon Pipeline1

1
1
Total$31
$29
$74
$68
Three Months Ended
March 31, 2018
Southern
Company
 
Alabama
Power
 
Georgia
Power
 
Mississippi
Power
 Southern Power Southern Company Gas
 (in millions)
Pension Plans
Service cost$90

$19

$22

$4

$2

$8
Interest cost116

25

35

5

1

10
Expected return on plan assets(236)
(51)
(74)
(10)
(3)
(18)
Amortization:           
Prior service costs1









(1)
Regulatory asset
 
 
 
 
 3
Net (gain)/loss53

14

17

3

1

3
Net periodic pension cost (income)$24

$7

$

$2

$1

$5
Postretirement Benefits
Service cost$6
 $1
 $2
 $
 $
 $1
Interest cost19
 4
 7
 1
 
 2
Expected return on plan assets(17) (6) (6) 
 
 (2)
Amortization:           
Prior service costs2
 1
 
 
 
 
Regulatory asset
 
 
 
 
 1
Net (gain)/loss3
 
 2
 
 
 
Net periodic postretirement benefit cost$13
 $
 $5
 $1
 $
 $2

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(UNAUDITED)

(I) FAIR VALUE MEASUREMENTS
As of March 31, 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 March 31, 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)(b)
$322
 $128
 $4
 $
 $454
Foreign currency derivatives
 38
 
 
 38
Investments in trusts:(c)(d)
         
Domestic equity682
 120
 
 
 802
Foreign equity60
 195
 
 
 255
U.S. Treasury and government agency securities
 283
 
 
 283
Municipal bonds
 73
 
 
 73
Pooled funds – fixed income
 14
 
 
 14
Corporate bonds24
 298
 
 
 322
Mortgage and asset backed securities
 72
 
 
 72
Private equity
 
 
 48
 48
Cash and cash equivalents1
 
 
 
 1
Other28
 4
 
 
 32
Cash equivalents907
 3
 
 
 910
Other investments9
 14
 
 
 23
Total$2,033
 $1,242
 $4
 $48
 $3,327
Liabilities:         
Energy-related derivatives(a)(b)
$466
 $106
 $23
 $
 $595
Interest rate derivatives
 35
 
 
 35
Foreign currency derivatives
 24
 
 
 24
Contingent consideration
 
 21
 
 21
Total$466
 $165
 $44
 $
 $675
          

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(UNAUDITED)

 Fair Value Measurements Using:  
As of March 31, 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:(c)
        

Domestic equity446
 108
 
 
 554
Foreign equity60
 57
 
 
 117
U.S. Treasury and government agency securities
 18
 
 
 18
Municipal bonds
 1
 
 
 1
Corporate bonds24
 139
 
 
 163
Mortgage and asset backed securities
 24
 
 
 24
Private equity
 
 
 48
 48
Other5
 
 
 
 5
Cash equivalents569
 3
 
 
 572
Other investments
 14
 
 
 14
Total$1,104
 $370
 $
 $48
 $1,522
Liabilities:         
Energy-related derivatives$
 $7
 $
 $
 $7
          
Georgia Power         
Assets:         
Energy-related derivatives$
 $9
 $
 $
 $9
Nuclear decommissioning trusts:(c)(d)
         
Domestic equity236
 1
 
 
 237
Foreign equity
 134
 
 
 134
U.S. Treasury and government agency securities
 265
 
 
 265
Municipal bonds
 72
 
 
 72
Corporate bonds
 160
 
 
 160
Mortgage and asset backed securities
 47
 
 
 47
Other23
 4
 
 
 27
Total$259
 $692
 $
 $
 $951
Liabilities:         
Energy-related derivatives$
 $16
 $
 $
 $16
Interest rate derivatives
 2
 
 
 2
Total$
 $18
 $
 $
 $18
          

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(UNAUDITED)

 Fair Value Measurements Using:  
As of March 31, 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 equivalents202
 
 
 
 202
Total$202
 $3
 $
 $
 $205
Liabilities:         
Energy-related derivatives$
 $6
 $
 $
 $6
          
Southern Power         
Assets:         
Energy-related derivatives$
 $1
 $
 $
 $1
Foreign currency derivatives
 38
 
 

38
Cash equivalents10
 
 
 
 10
Total$10
 $39
 $
 $
 $49
Liabilities:         
Energy-related derivatives$
 $3
 $
 $
 $3
Foreign currency derivatives
 24
 
 
 24
Contingent consideration
 
 21
 
 21
Total$

$27

$21

$

$48
          
Southern Company Gas         
Assets:         
Energy-related derivatives(a)(b)
$322
 $108
 $4
 $
 $434
Non-qualified deferred compensation trusts:         
Domestic equity
 11
 
 
 11
Foreign equity
 4
 
 
 4
Pooled funds – fixed income
 14
 
 
 14
Cash equivalents1
 
 
 
 1
Cash equivalents13
 
 
 
 13
Total$336

$137

$4

$

$477
Liabilities:         
Energy-related derivatives(a)(b)
$466
 $73
 $23
 $
 $562
(a)
Energy-related derivatives exclude $11 million associated with premiums and certain weather derivatives accounted for based on intrinsic value rather than fair value.
(b)
Energy-related derivatives exclude cash collateral of $190 million.
(c)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.
(d)
Includes investment securities pledged to creditors and collateral received and excludes payables related to the securities lending program. As of March 31, 2019, approximately $72 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.

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(UNAUDITED)

Southern Natural Gas
Selected financial informationCompany, 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 SNGthe funds, including reinvested interest and dividends and excluding the funds' expenses, increased for the three and six months ended June 30,March 31, 2019 and decreased for the three months ended March 31, 2018 by the amounts shown in the table below. The changes were recorded as a change to the regulatory assets and June 30,liabilities related to AROs for Georgia Power and Alabama Power, respectively.
 
Three Months Ended
March 31, 2019
Three Months
Ended
March 31, 2018
 (in millions)
Southern Company$152
$(11)
Alabama Power87
(5)
Georgia Power65
(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.

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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.
As of March 31, 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 $48 million and unfunded commitments related to the private equity investments totaled $49 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 March 31, 2019, other financial instruments for which the carrying amount did not equal fair value were as follows:
 
Southern
Company
Alabama PowerGeorgia PowerMississippi PowerSouthern Power
Southern Company Gas(*)
 (in millions)
Long-term debt, including securities due within one year:    
Carrying amount$42,535
$7,921
$10,910
$1,619
$4,995
$5,928
Fair value43,910
8,424
11,249
1,619
5,131
6,176
(*)The long-term debt of Southern Company Gas is recorded at amortized cost, including the fair value adjustments at the effective date of the Merger. 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 March 31, 2019, the fair value of Southern Company Gas' Level 3 physical natural gas forward contracts was $19 million. Since commodity contracts classified as Level 3 typically include a combination of observable and unobservable components, the changes in fair value may include amounts due in part to observable market factors, or changes to assumptions on the unobservable components. The following table includes transfers to Level 3, which represent the fair value of Southern Company Gas' commodity derivative contracts that include a significant unobservable component for the first time during the period.
 Three Months Ended March 31, 2019
 (in millions)
Beginning balance$
Transfers to Level 3(30)
Changes in fair value11
Ending balance$(19)
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

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(UNAUDITED)

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 $0.07 to $1.15 per mmBtu). Forward price increases (decreases) as of March 31, 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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(UNAUDITED)

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 March 31, 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(*)
538 2022 2029
Alabama Power72 2022 
Georgia Power153 2022 
Mississippi Power61 2022 
Southern Power9 2020 
Southern Company Gas(*)
243 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 3.8 billion mmBtu and short natural gas positions of 3.6 billion mmBtu as of March 31, 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 40 million mmBtu for Southern Company, which includes 6 million mmBtu for Alabama Power, 12 million mmBtu for Georgia Power, 5 million mmBtu for Mississippi Power, and 13 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 next 12-month period ending March 31, 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

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(UNAUDITED)

hedges where the derivatives' fair value gains or losses are recorded in OCI and are reclassified into earnings at the same time and presented on the same income statement line item as the earnings effect of the hedged transactions. Derivatives related to existing fixed rate securities are accounted for as fair value hedges, where the derivatives' fair value gains or losses and hedged items' fair value gains or losses are both recorded directly to earnings on the same income statement line item. Fair value gains or losses on derivatives that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.
At March 31, 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 March 31, 2019
 (in millions)     (in millions)
Fair Value Hedges of Existing Debt      
Southern Company(*)
$300
 2.75%3-month LIBOR+0.92%June 2020 $(3)
Southern Company(*)
1,500
 2.35%1-month LIBOR+0.87%July 2021 (30)
Georgia Power200
 4.25%3-month LIBOR+2.46%December 2019 (2)
Southern Company Consolidated$2,000
     $(35)
(*)Represents the Southern Company parent entity.
The estimated pre-tax gains (losses) related to interest rate derivatives expected to be reclassified from accumulated OCI to interest expense for the next 12-month period ending March 31, 2020 are $(19) 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, 2037 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.
At March 31, 2019, the following foreign currency derivatives were outstanding:
 Pay NotionalPay RateReceive NotionalReceive RateHedge
Maturity Date
Fair Value Gain (Loss) at March 31, 2019
 (in millions) (in millions)  (in millions)
Cash Flow Hedges of Existing Debt     
Southern Power$677
2.95%600
1.00%June 2022$2
Southern Power564
3.78%500
1.85%June 202611
Total$1,241
 1,100
  $13

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(UNAUDITED)

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 next 12-month period ending March 31, 2020 are $(24) 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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(UNAUDITED)

The fair value of energy-related derivatives, interest rate derivatives, and foreign currency derivatives was reflected in the balance sheets as follows:
 As of March 31, 2019As of December 31, 2018
Derivative Category and Balance Sheet LocationAssetsLiabilitiesAssetsLiabilities
 (in millions)(in millions)
Southern Company    
Derivatives designated as hedging instruments for regulatory purposes    
Energy-related derivatives:    
Other current assets/Other current liabilities$12
$10
$8
$23
Other deferred charges and assets/Other deferred credits and liabilities11
21
9
26
Assets held for sale, current/Liabilities held for sale, current


6
Total derivatives designated as hedging instruments for regulatory purposes$23
$31
$17
$55
Derivatives designated as hedging instruments in cash flow and fair value hedges    
Energy-related derivatives:    
Other current assets/Other current liabilities$1
$3
$3
$7
Other deferred charges and assets/Other deferred credits and liabilities
1
1
2
Interest rate derivatives:    
Other current assets/Other current liabilities
20

19
Other deferred charges and assets/Other deferred credits and liabilities
15

30
Foreign currency derivatives:    
Other current assets/Other current liabilities
24

23
Other deferred charges and assets/Other deferred credits and liabilities38

75

Total derivatives designated as hedging instruments in cash flow and fair value hedges$39
$63
$79
$81
Derivatives not designated as hedging instruments    
Energy-related derivatives:    
Other current assets/Other current liabilities$259
$291
$561
$575
Other deferred charges and assets/Other deferred credits and liabilities171
269
180
325
Total derivatives not designated as hedging instruments$430
$560
$741
$900
Gross amounts recognized$492
$654
$837
$1,036
Gross amounts offset(a)
$(333)$(523)$(524)$(801)
Net amounts recognized in the Balance Sheets(b)
$159
$131
$313
$235
     

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(UNAUDITED)

 As of March 31, 2019As of December 31, 2018
Derivative Category and Balance Sheet LocationAssetsLiabilitiesAssetsLiabilities
 (in millions)(in millions)
Alabama Power    
Derivatives designated as hedging instruments for regulatory purposes    
Energy-related derivatives:    
Other current assets/Other current liabilities$3
$2
$3
$4
Other deferred charges and assets/Other deferred credits and liabilities3
5
3
6
Total derivatives designated as hedging instruments for regulatory purposes$6
$7
$6
$10
Gross amounts recognized$6
$7
$6
$10
Gross amounts offset$(5)$(5)$(4)$(4)
Net amounts recognized in the Balance Sheets$1
$2
$2
$6
     
Georgia Power    
Derivatives designated as hedging instruments for regulatory purposes    
Energy-related derivatives:    
Other current assets/Other current liabilities$4
$5
$2
$8
Other deferred charges and assets/Other deferred credits and liabilities5
11
4
13
Total derivatives designated as hedging instruments for regulatory purposes$9
$16
$6
$21
Derivatives designated as hedging instruments in cash flow and fair value hedges    
Interest rate derivatives:    
Other current assets/Other current liabilities$
$2
$
$2
Total derivatives designated as hedging instruments in cash flow and fair value hedges$
$2
$
$2
Gross amounts recognized$9
$18
$6
$23
Gross amounts offset$(8)$(8)$(6)$(6)
Net amounts recognized in the Balance Sheets$1
$10
$
$17
     

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 As of March 31, 2019As of December 31, 2018
Derivative Category and Balance Sheet LocationAssetsLiabilitiesAssetsLiabilities
 (in millions)(in millions)
Mississippi Power    
Derivatives designated as hedging instruments for regulatory purposes    
Energy-related derivatives:    
Other current assets/Other current liabilities$2
$2
$1
$3
Other deferred charges and assets/Other deferred credits and liabilities1
4
2
6
Total derivatives designated as hedging instruments for regulatory purposes$3
$6
$3
$9
Gross amounts recognized$3
$6
$3
$9
Gross amounts offset$(3)$(3)$(2)$(2)
Net amounts recognized in the Balance Sheets$
$3
$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
$2
$3
$6
Other deferred charges and assets/Other deferred credits and liabilities
1
1
2
Foreign currency derivatives:    
Other current assets/Other current liabilities
24

23
Other deferred charges and assets/Other deferred credits and liabilities38

75

Total derivatives designated as hedging instruments in cash flow and fair value hedges$39
$27
$79
$31
Gross amounts recognized$39
$27
$79
$31
Gross amounts offset$(1)$(1)$(3)$(3)
Net amounts recognized in the Balance Sheets$38
$26
$76
$28
     
Southern Company Gas    
Derivatives designated as hedging instruments for regulatory purposes    
Energy-related derivatives:    
Assets from risk management activities/Liabilities from risk management activities-current$3
$1
$2
$8
Other deferred charges and assets/Other deferred credits and liabilities1


1
Total derivatives designated as hedging instruments for regulatory purposes$4
$1
$2
$9
Derivatives designated as hedging instruments in cash flow and fair value hedges    
Energy-related derivatives:    
Assets from risk management activities/Liabilities from risk management activities-current$
$1
$
$1
Total derivatives designated as hedging instruments in cash flow and fair value hedges$
$1
$
$1

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 As of March 31, 2019As of December 31, 2018
Derivative Category and Balance Sheet LocationAssetsLiabilitiesAssetsLiabilities
 (in millions)(in millions)
Derivatives not designated as hedging instruments    
Energy-related derivatives:    
Assets from risk management activities/Liabilities from risk management activities-current$259
$291
$559
$574
Other deferred charges and assets/Other deferred credits and liabilities171
269
180
325
Total derivatives not designated as hedging instruments$430
$560
$739
$899
Gross amounts of recognized$434
$562
$741
$909
Gross amounts offset(a)
$(316)$(506)$(508)$(785)
Net amounts recognized in the Balance Sheets(b)
$118
$56
$233
$124
(a)Gross amounts offset include cash collateral held on deposit in broker margin accounts of $190 million and $277 million as of March 31, 2019 and December 31, 2018, respectively.
(b)Net amounts of derivative instruments outstanding exclude premium and intrinsic value associated with weather derivatives of $11 million and $8 million as of March 31, 2019 and December 31, 2018, respectively.
At March 31, 2019 and December 31, 2018, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred were as follows:
Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at March 31, 2019
Derivative Category and Balance Sheet
Location
Southern
Company(*)
Alabama
Power
Georgia
Power
Mississippi
Power
Southern Company Gas(*)
 (in millions)
Energy-related derivatives:     
Other regulatory assets, current$(5)$(1)$(2)$(1)$(1)
Other regulatory assets, deferred(11)(2)(6)(3)
Other regulatory liabilities, current7
1
1
1
4
Total energy-related derivative gains (losses)$(9)$(2)$(7)$(3)$3
(*)Fair value gains and losses recorded in regulatory assets and liabilities include cash collateral held on deposit in broker margin accounts of $2 million at March 31, 2019.
Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheet at December 31, 2018
Derivative Category and Balance Sheet
Location
Southern
Company
Alabama
Power
Georgia
Power
Mississippi
Power
Southern Company Gas
 (in millions)
Energy-related derivatives:     
Other regulatory assets, current$(19)$(3)$(6)$(2)$(8)
Other regulatory assets, deferred(16)(3)(9)(4)
Assets held for sale, current(6)



Other regulatory liabilities, current1



1
Total energy-related derivative gains (losses)$(40)$(6)$(15)$(6)$(7)

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For the three months ended March 31, 2019 and 2018, the pre-tax effects of cash flow hedge accounting on accumulated OCI were as follows:
Gain (Loss) Recognized in OCI on DerivativeFor the Three Months
Ended March 31,
20192018
 (in millions)
Southern Company  
Energy-related derivatives$
$12
Interest rate derivatives
(2)
Foreign currency derivatives(39)53
Total$(39)$63
Southern Power  
Energy-related derivatives$
$11
Foreign currency derivatives(39)53
Total$(39)$64
For the three months ended March 31, 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.
For the three months ended March 31, 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 RelationshipsFor the Three Months
Ended March 31,
 
 20192018
  (in millions)
 Southern Company  
 Total depreciation and amortization$751
$769
 
Gain (loss) on energy-related cash flow hedges(a)
(3)1
 Total interest expense, net of amounts capitalized(430)(458)
 
Gain (loss) on interest rate cash flow hedges(a)
(5)(5)
 
Gain (loss) on foreign currency cash flow hedges(a)
(6)(5)
 
Gain (loss) on interest rate fair value hedges(b)
14
(24)
 Total other income (expense), net78
60
 
Gain (loss) on foreign currency cash flow hedges(a)(c)
(24)36
 Southern Power  
 Total depreciation and amortization$119
$114
 
Gain (loss) on energy-related cash flow hedges(a)
(3)1
 Total interest expense, net of amounts capitalized(44)(47)
 
Gain (loss) on foreign currency cash flow hedges(a)
(6)(5)
 Total other income (expense), net2
3
 
Gain (loss) on foreign currency cash flow hedges(a)(c)
(24)36
(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.

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For the three months ended March 31, 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 March 31, 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 ItemsAs of March 31, 2019As of December 31, 2018
As of March 31, 2019As of December 31, 2018

(in millions) (in millions)
Southern Company     
Securities due within one year$(499)$(498) $1
$2
Long-term debt(2,065)(2,052) 28
41
      
Georgia Power     
Securities due within one year$(499)$(498) $1
$2
Long-term debt

 

For the three months ended March 31, 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 March 31,
Derivatives in Non-Designated Hedging RelationshipsStatements of Income Location20192018
  (in millions)
Energy-related derivatives:
Natural gas revenues(*)
$33
$(15)
 Cost of natural gas8
2
Total derivatives in non-designated hedging relationships$41
$(13)
(*)Excludes immaterial gains (losses) recorded in natural gas revenues associated with weather derivatives for the three months ended March 31, 2019 and 2018.
For the three months ended March 31, 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 March 31, 2019, the registrants had no collateral posted with derivative counterparties to satisfy these arrangements.
For the registrants with interest rate derivatives at March 31, 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 March 31, 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

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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 March 31, 2019, cash collateral posted in these accounts was immaterial. Southern Company Gas maintains accounts with brokers or the clearing houses of certain exchanges to facilitate financial derivative transactions. Based on the value of the positions in these accounts and the associated margin requirements, Southern Company Gas may be required to deposit cash into these accounts. At March 31, 2019, cash collateral held on deposit in broker margin accounts was $190 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.
Management has started the process to sell one of PowerSecure's business units; therefore, the related assets and liabilities have been reclassified as held for sale on Southern Company's balance sheet as of March 31, 2019. The ultimate outcome of this matter cannot be determined at this time; however, any related gain or loss on the potential sale is not expected to have a material effect on Southern Company's financial statements.
See "Assets Held for Sale" herein for additional information.
Southern Power
Construction Projects in Progress
During the three months ended March 31, 2019, Southern Power continued construction of the projects set forth in the table below. Total aggregate construction costs, excluding the acquisition costs, are expected to be between $575 million and $640 million for the Plant Mankato expansion and the Wildhorse Mountain and Reading facilities. At March 31, 2019, total costs of construction incurred for these projects were $347 million and are included in CWIP, except for the Plant Mankato expansion, which is included in assets held for sale in the financial statements. The ultimate outcome of these matters cannot be determined at this time.
Project FacilityResource
Approximate Nameplate Capacity (MW)
LocationExpected CODPPA Contract Period
Mankato expansion(a)
Natural Gas385Mankato, MNMay 201920 years
Wildhorse Mountain(b)
Wind100Pushmataha County, OKFourth quarter 201920 years
Reading(c)
Wind200Osage and Lyon Counties, KSSecond quarter 202012 years
(a)
In November 2018, Southern Power entered into an agreement to sell all of its equity interests in Plant Mankato, including this expansion currently under construction. This transaction is subject to FERC and state commission approvals and is expected to close mid-2019. The ultimate outcome of this matter cannot be determined at this time. See "Sales of Natural Gas and Biomass Plants" below.
(b)
In May 2018, Southern Power purchased 100% of the Wildhorse Mountain facility. Southern Power may enter into a tax equity partnership, in which case it would then own 100% of the class B membership interests. The ultimate outcome of this matter cannot be determined at this time.
(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. described below. Southern Power may enter into a tax equity partnership, in which case it would then own 100% of the class B membership interests. The ultimate outcome of this matter cannot be determined at this time.
Development Projects
Southern Power continues to evaluate and refine the deployment of the 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 three months ended March 31, 2019, approximately $53 million of equipment was marketed for sale and, subsequent to March 31, 2019, was sold. At March 31, 2019, the equipment was classified as held for

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sale on Southern Company's and Southern Power's balance sheets. See "Assets Held for Sale" herein for additional information.
The ultimate outcome of these matters cannot be determined at this time.
Sales of Natural Gas and Biomass Plants
In November 2018, Southern Power entered into an agreement with Northern States Power to sell all of its equity interests in Plant Mankato (including the 385-MW expansion currently under construction) for an aggregate purchase price of approximately $650 million. The completion of the disposition is subject to the expansion unit reaching commercial operation as well as various other customary conditions to closing, including working capital and timing adjustments. This transaction is subject to FERC and state commission approvals. 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 March 31, 2019 and December 31, 2018. See "Assets Held for Sale" herein for additional information.
On April 17, 2019, Southern Power entered into an agreement to sell all of its equity interests in the Nacogdoches biomass-fueled facility to Austin Energy for an aggregate purchase price of $460 million, subject to customary closing conditions and working capital adjustments.
Each of these sales is expected to close in mid-2019; however, the ultimate outcome of these matters cannot be determined at this time.
Assets Subject to Lien
Under the terms of the PPA and the expansion PPA for Plant Mankato, approximately $538 million of assets, primarily related to property, plant, and equipment, are subject to lien at March 31, 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 March 31, 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 for Plant Mankato, 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 March 31, 2019 and December 31, 2018:
 Southern Company
Southern
Power
 (in millions)
At March 31, 2019  
Assets Held for Sale:  
Current assets$55
$11
Total property, plant, and equipment637
604
Goodwill and other intangible assets82
40
Other non-current assets44

Total Assets Held for Sale$818
$655
   
Liabilities Held for Sale:  
Current liabilities$38
$9
Other non-current liabilities39

Total Liabilities Held for Sale$77
$9
   
At December 31, 2018  
Assets Held for Sale:  
Current assets$393
$8
Total property, plant, and equipment4,583
536
Goodwill and other intangible assets40
40
Other non-current assets727

Total Assets Held for Sale$5,743
$584
   
Liabilities Held for Sale:  
Current liabilities$425
$15
Long-term debt1,286

Accumulated deferred income taxes618

Other non-current liabilities932

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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(UNAUDITED)

Gulf Power and Southern Power's equity interests in Plant Oleander and Plant Stanton Unit A (together, the Florida Plants) represented individually significant components of Southern Company and Southern Power, respectively; therefore, pre-tax profit for these components for the three months ended March 31, 2018 is presented below:
 For the Three Months
Ended March 31, 2018
 (in millions)
Earnings before income taxes: 
Gulf Power$55
Southern Power's Florida Plants$8
(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 March 31, 2019
 
Southern
Company
Alabama
Power
Georgia
Power
Mississippi
Power
Southern PowerSouthern Company Gas
 (in millions)
Electric generating units$1,094
$159
$1,606
$
$
$
Real estate/land803
3
63
2
393
83
Communication towers131
1
3



Railcars55
25
26
3


Other153
10
16
3

1
Total$2,236
$198
$1,714
$8
$393
$84
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 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.

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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 $670 million at March 31, 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 March 31, 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.
Balance sheet amounts recorded for operating and finance leases are as follows:
 As of March 31, 2019
 
Southern
 Company(*)
Alabama
Power
Georgia
Power
Mississippi
Power
Southern PowerSouthern Company Gas
 (in millions)
Operating Leases      
Operating lease ROU assets, net$1,926
$160
$1,519
$8
$372
$86
       
Operating lease obligations - current$239
$47
$139
$3
$22
$13
Operating lease obligations - non current1,752
147
1,404
5
371
71
Total operating lease obligations$1,991
$194
$1,543
$8
$393
$84
       
Finance Leases      
Finance lease ROU assets, net$242
$4
$145
$
$
$
       
Finance lease obligations - current$38
$1
$10
$
$
$
Finance lease obligations - noncurrent207
3
161



Total finance lease obligations$245
$4
$171
$
$
$
(*)Includes operating lease ROU assets, net and operating lease obligations classified as held for sale.

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Lease costs for the three months ended March 31, 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:
 For the Three Months Ended March 31, 2019
 
Southern
Company
Alabama
Power
Georgia
Power
Mississippi
Power
Southern PowerSouthern Company Gas
 (in millions)
Lease cost      
Operating lease cost$69
$7
$49
$1
$7
$4
Finance lease cost:      
Amortization of ROU assets7

4



Interest on lease obligations3

4



Total finance lease cost10

8



Short-term lease costs14
5
3



Variable lease cost19

16

1

Sublease income





Total lease cost$112
$12
$76
$1
$8
$4
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:
Income Statement Information
Three Months Ended
June 30, 2018
Three Months Ended
June 30, 2017
Six Months Ended
June 30, 2018
Six Months
Ended
June 30, 2017
 (in millions)
Revenues$146
$143
$306
$298
Operating income$60
$63
$159
$147
Net income$54
$48
$132
$114
 For the Three Months Ended March 31, 2019
 
Southern
Company
Alabama
Power
Georgia
Power
Mississippi
Power
Southern PowerSouthern Company Gas
 (in millions)
Other information      
Cash paid for amounts included in the measurements of lease obligations:      
Operating cash flows from operating leases$74
$13
$32
$1
$7
$4
Operating cash flows from finance leases6

13



Financing cash flows from finance leases8

2



ROU assets obtained in exchange for new operating lease obligations15
2
4



ROU assets obtained in exchange for new finance lease obligations29

28




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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

 As of March 31, 2019
 
Southern
Company
Alabama
Power
Georgia
Power
Mississippi
Power
Southern PowerSouthern Company Gas
Weighted-average remaining lease term in years:      
Operating leases13.5
3.8
10.1
6.8
33.7
9.0
Finance leases18.5
14.8
11.3



Weighted-average discount rate:      
Operating leases4.49%3.33%4.42%4.03%5.68%3.70%
Finance leases5.00%3.75%10.68%%%%
Maturities of lease liabilities are as follows:
 As of March 31, 2019
 
Southern
Company
Alabama
Power
Georgia
Power
Mississippi
Power
Southern PowerSouthern Company Gas
 (in millions)
Maturity Analysis      
Operating leases:      
2019 (remaining)$253
$46
$182
$2
$17
$12
2020291
53
202
2
22
16
2021274
52
197
1
23
16
2022263
52
195
1
23
12
2023198
3
196
1
24
10
Thereafter1,637
1
984
2
848
36
Total2,916
207
1,956
9
957
102
Less: Present value discount925
13
413
1
564
18
Operating lease obligations$1,991
$194
$1,543
$8
$393
$84
Finance leases:      
2019 (remaining)$24
$1
$22
$
$
$
202032
1
28



202126
1
25



202222
1
25



202318
1
25



Thereafter273

165



Total395
5
290



Less: Present value discount150
1
119



Finance lease obligations$245
$4
$171
$
$
$
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 March 31, 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 2021, with lease terms of up to 30 years, and have estimated total obligations of $77 million.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

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 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 months ended March 31, 2019 is as follows:
 For the Three Months Ended March 31, 2019
 
Southern
Company
Georgia Power
Mississippi
Power
Southern PowerSouthern Company Gas
 (in millions)
Lease income - interest income on sales-type leases$2
$
$2
$
$
Lease income - operating leases71
19

41
9
Variable lease income66


72

Total lease income$139
$19
$2
$113
$9
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.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

The undiscounted cash flows to be received under tolling arrangements accounted for as sales-type leases are as follows:
 As of March 31, 2019
 
Southern
Company
Mississippi
Power
 (in millions)
2019 (remaining)$11
$11
202014
14
202114
14
202213
13
202312
12
Thereafter135
135
Total undiscounted cash flows$199
$199
Lease receivable108
108
Difference between undiscounted cash flows and discounted cash flows$91
$91
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 March 31, 2019
 
Southern
Company
Georgia Power
Southern
Power
Southern Company Gas
 (in millions)
2019 (remaining)$163
$20
$123
$26
2020188
26
128
34
2021183
18
131
34
2022174
8
134
34
2023171
2
137
34
Thereafter1,809

1,017
498
Total$2,688
$74
$1,670
$660
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.
(L)(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 four traditional electric operating companies – Alabama Power, Georgia Power, Gulf Power, and Mississippi Power – are vertically integrated utilities providing electric service in fourthree Southeastern states. Southern Power develops, constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through its natural gas distribution utilities in four states and is involved in several other complementary businesses including gas marketing services,pipeline investments, wholesale gas services, and gas midstream operations. Through June 30, 2018, Southern Company Gas had seven natural gas distribution utilities in seven states. Subsequent to June 30, 2018, Southern Company Gas completed salesmarketing services.

194

Table of three of its natural gas distribution utilities. See Note (J) under "Southern Company Gas" for additional information.Contents

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

Southern Company's reportable business segments are the sale of electricity by the four traditional electric operating companies, the sale of electricity in the competitive wholesale market by Southern Power, and the sale of natural gas and other complementary products and services by Southern Company Gas. Revenues from sales by Southern Power to the traditional electric operating companies were $109 million and $192$87 million for the three and six months ended June 30, 2018, respectively,March 31, 2019 and $90 million and $190$83 million for the three and six months ended June 30, 2017, respectively.March 31, 2018. Revenues from sales of natural gas from Southern Company Gas to the traditional electric operating companies were $8 millionimmaterial for botheach of the three and six months ended June 30, 2018March 31, 2019 and $10 million for both the three and six months ended June 30, 2017.2018. Revenues from sales of natural gas from Southern Company Gas to Southern Power were $22 million and $58$17 million for the three and six months ended June 30, 2018, respectively,March 31, 2019 and $33 million and $56$36 million for the three and six months ended June 30, 2017, respectively.March 31, 2018. The "All Other" column includes the Southern Company parent entity, which does not allocate operating expenses to

NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

business segments. Also, this category includes segments below the quantitative threshold for separate disclosure. These segments include providing energy technologies and services to electric utilities and large industrial, commercial, institutional, and municipal customers;customers, as well as investments in telecommunications and leveraged lease projects. All other inter-segment revenues are not material.
Financial data for business segments and products and services for the three and six months ended June 30,March 31, 2019 and 2018 and 2017 was as follows:
Electric Utilities Electric Utilities 
Traditional
Electric Operating
Companies
Southern
Power
EliminationsTotalSouthern Company Gas
All
Other
EliminationsConsolidated
Traditional
Electric Operating
Companies
Southern
Power
EliminationsTotalSouthern Company Gas
All
Other
EliminationsConsolidated
(in millions)(in millions)
Three Months Ended June 30, 2018: 
Three Months Ended March 31, 2019:Three Months Ended March 31, 2019: 

 
Operating revenues$4,124
$555
$(114)$4,565
$730
$381
$(49)$5,627
$3,445
$443
$(93)$3,795
$1,474
$182
$(39)$5,412
Segment net income (loss)(a)(b)(c)
(48)22

(26)(31)(100)3
(154)565
56

621
270
1,195
(2)2,084
Six Months Ended June 30, 2018: 

 
Operating revenues$8,104
$1,064
$(220)$8,948
$2,369
$782
$(100)$11,999
Segment net income (loss)(a)(b)(c)(d)
563
143

706
248
(174)4
784
At June 30, 2018: 
At March 31, 2019: 
Goodwill$
$2
$
$2
$5,015
$298
$
$5,315
$
$2
$
$2
$5,015
$268
$(1)$5,284
Total assets73,634
15,428
(313)88,749
22,112
3,707
(1,791)112,777
76,798
15,104
(779)91,123
20,952
3,391
(1,370)114,096
Three Months Ended June 30, 2017: 
Three Months Ended March 31, 2018:Three Months Ended March 31, 2018: 
Operating revenues$4,157
$529
$(101)$4,585
$716
$166
$(37)$5,430
$3,979
$509
$(106)$4,382
$1,639
$401
$(50)$6,372
Segment net income (loss)(a)(b)
(1,442)82

(1,360)49
(68)(2)(1,381)
Six Months Ended June 30, 2017: 
Operating revenues$7,943
$979
$(206)$8,716
$2,276
$289
$(79)$11,202
Segment net income (loss)(a)(b)(e)
(1,010)151

(859)288
(152)
(723)
At December 31, 2017: 
Segment net income (loss)(a)(b)(d)
612
121

733
279
(74)
938
At December 31, 2018: 
Goodwill$
$2
$
$2
$5,967
$299
$
$6,268
$
$2
$
$2
$5,015
$298
$
$5,315
Total assets72,204
15,206
(325)87,085
22,987
2,552
(1,619)111,005
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 $1.1 billion$2 million ($0.8 billion1 million after tax) and $3.0 billion$44 million ($2.1 billion33 million after tax) for the three months ended June 30,March 31, 2019 and 2018, and 2017, respectively, and $1.1 billion ($0.8 billion after tax) and $3.1 billion ($2.2 billion after tax) for the six months ended June 30, 2018 and 2017, respectively. See Note 32 to the financial statements of Southern Company under "Kemper County Energy Facility" in Item 8 of the Form 10-K and Note (B) under "Nuclear ConstructionMississippi Power" and "Kemper County Energy Facility" for additional information.
(c)
Segment net income (loss) for Southernthe "All Other" column includes the preliminary pre-tax gain associated with the sale of Gulf Power includes a pre-tax impairment charge of $119 million$2.5 billion ($89 million1.3 billion after tax) for the three and six months ended June 30, 2018 related to the pending sale of Southern Power's Florida Plants.March 31, 2019. See Note (J)(K) under "Southern Power – "Sale of Florida PlantsSouthern Company" for additional information.
(d)
Segment net income (loss) for Southern Company Gas includes a goodwill impairment charge of $42 million for the sixthree months ended June 30,March 31, 2018 related to the sale of Pivotal Home Solutions. See Note (J) under "Southern Company GasSale of Pivotal Home Solutions" for additional information.
(e)Segment net income (loss) for the traditional electric operating companies includes a pre-tax charge for the write-down of Gulf Power's ownership of Plant Scherer Unit 3 of $33 million ($20 million after tax) for the six months ended June 30, 2017. See Note 315 to the financial statements of Southern Company under "Regulatory Matters – Gulf Power – Retail Base Rate Cases" in Item 8 of the Form 10-K under "Southern Company Gas" for additional information.

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NOTES TO THE CONDENSED FINANCIAL STATEMENTS: (Continued)
(UNAUDITED)

Products and Services
 Electric Utilities' Revenues
PeriodRetailWholesaleOtherTotal
 (in millions)
Three Months Ended June 30, 2018$3,740
$611
$214
$4,565
Three Months Ended June 30, 20173,777
618
190
4,585
     
Six Months Ended June 30, 2018$7,308
$1,230
$410
$8,948
Six Months Ended June 30, 20177,171
1,149
396
8,716
 Electric Utilities' Revenues
 RetailWholesaleOtherTotal
 (in millions)
Three Months Ended March 31, 2019$3,084
$499
$212
$3,795
Three Months Ended March 31, 20183,568
623
191
4,382
 Southern Company Gas' Revenues
PeriodGas
Distribution
Operations
Gas
Marketing
Services
OtherTotal
 (in millions)
Three Months Ended June 30, 2018$638
$89
$3
$730
Three Months Ended June 30, 2017557
166
(7)716
     
Six Months Ended June 30, 2018$1,838
$359
$172
$2,369
Six Months Ended June 30, 20171,689
454
133
2,276
 Southern Company Gas' Revenues
 
Gas
Distribution
Operations
(a)
Gas
Marketing
Services
(b)
OtherTotal
 (in millions)
Three Months Ended March 31, 2019$1,161
$229
$84
$1,474
Three Months Ended March 31, 20181,200
271
168
1,639
(a)Operating revenues for the three gas distribution operations dispositions were $167 million for the three months ended March 31, 2018.
(b)Operating revenues for Pivotal Home Solutions were $32 million for the three months ended March 31, 2018.
Southern Company Gas
Southern Company Gas manages its business through four reportable segments – gas distribution operations, gas marketing services,pipeline investments, wholesale gas services, and gas midstream operations.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 sevenfour states. Subsequent
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 June 30, 2018,the customers of Southern Company Gas sold three of its natural gas distribution utilities, Elizabethtown Gas, Elkton Gas, and Florida City Gas. See Note (J) under "Southern Company Gas" for additional information.
Gas marketing services includes natural gas marketing to end-use customers primarily in Georgia and Illinois. On June 4, 2018, Southern Company Gas sold Pivotal Home Solutions. See Note (J) under "Southern Company Gas" for additional information.
Wholesale gas services provides natural gas asset management and/or related logistics services for each of Southern Company Gas' utilities except Nicor Gas as well as for non-affiliated companies. Additionally, wholesale gas services engages in natural gas storage and gas pipeline arbitrage and related activities.
Gas midstream operationsmarketing services provides natural gas marketing to end-use customers primarily consists of Southern Company Gas' pipeline investments, with storagein Georgia and fuel operations also aggregated into this segment.Illinois through SouthStar Energy Services, LLC.
The all other column includes segments below the quantitative threshold for separate disclosure, including the storage and fuels operations, and the other subsidiaries that fall below the quantitative threshold for separate disclosure.

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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,March 31, 2019 and 2018 and 2017 was as follows:
 
Gas Distribution Operations(a)
Gas Marketing Services(b)(c)
Wholesale Gas Services(d)
Gas Midstream OperationsTotalAll OtherEliminationsConsolidated
 (in millions)
Three Months Ended June 30, 2018:      
Operating revenues$643
$89
$(16)$18
$734
$1
$(5)$730
Segment net income68
(76)(21)14
(15)(16)
(31)
Six Months Ended June 30, 2018:      
Operating revenues1,856
359
150
40
2,405
2
(38)2,369
Segment net income216
(63)83
38
274
(26)
248
Total assets at June 30, 2018:18,654
1,610
818
2,269
23,351
11,544
(12,783)22,112
Three Months Ended June 30, 2017:      
Operating revenues$603
$166
$(12)$12
$769
$3
$(56)$716
Segment net income54
4
(17)9
50
(1)
49
Six Months Ended June 30, 2017:       
Operating revenues1,783
454
119
37
2,393
5
(122)2,276
Segment net income171
35
51
25
282
6

288
Total assets at December 31, 2017:19,358
2,147
1,096
2,241
24,842
12,184
(14,039)22,987
 
Gas Distribution Operations(a)
Gas Pipeline Investments
Wholesale Gas Services(b)
Gas Marketing Services(c)(d)
TotalAll OtherEliminationsConsolidated
 (in millions)
Three Months Ended March 31, 2019:      
Operating revenues$1,172
$8
$86
$229
$1,495
$11
$(32)$1,474
Segment net income (loss)133
32
47
61
273
(3)
270
Total assets at March 31, 2019:17,379
1,781
821
1,611
21,592
10,900
(11,540)20,952
Three Months Ended March 31, 2018:       
Operating revenues$1,212
$8
$166
$271
$1,657
$15
$(33)$1,639
Segment net income (loss)149
27
104
13
293
(14)
279
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 $66$167 million for the three months ended June 30, 2018 and 2017, respectively, and $237 million and $224 million for the six months ended June 30, 2018 and 2017, respectively.March 31, 2018. See Note (J)15 to the financial statements in Item 8 of the Form 10-K under "Southern"Southern Company Gas"Gas" for additional information.
(b)
Operating revenues for the gas marketing services disposition were $24 million and $32 million for the three months ended June 30, 2018 and 2017, respectively, and $55 million and $63 million for the six months ended June 30, 2018 and 2017, respectively. See Note (J) under "Southern Company Gas" for additional information.
(c)
Segment net income for gas marketing services includes a loss on disposition of $36 million for the three and six months ended June 30, 2018 and a goodwill impairment charge of $42 million for the six months ended June 30, 2018 recorded in contemplation of the sale of Pivotal Home Solutions. See Note (J) under "Southern Company Gas" for additional information.
(d)The revenues for wholesale gas services are netted with costs associated with its energy and risk management activities. A reconciliation of operating revenues and intercompany revenues is shown in the following table.
 Third Party Gross RevenuesIntercompany RevenuesTotal Gross RevenuesLess Gross Gas CostsOperating Revenues
 (in millions)
Three Months Ended June 30, 2018$1,336
$102
$1,438
$1,454
$(16)
Three Months Ended June 30, 20171,531
123
1,654
1,666
(12)
Six Months Ended June 30, 2018$3,274
$269
$3,543
$3,393
$150
Six Months Ended June 30, 20173,370
259
3,629
3,510
119
 Third Party Gross RevenuesIntercompany RevenuesTotal Gross RevenuesLess Gross Gas CostsOperating Revenues
 (in millions)
Three Months Ended March 31, 2019$1,926
$88
$2,014
$1,928
$86
Three Months Ended March 31, 20181,938
167
2,105
1,939
166
(c)Operating revenues for the gas marketing services disposition were $32 million for the three months ended March 31, 2018. See Note 15 to the financial statements in Item 8 of the Form 10-K under "Southern Company Gas" for additional information.
(d)Segment net income (loss) for gas marketing services includes a goodwill impairment charge of $42 million for the three months ended March 31, 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. Except as described below, thereThere have been no material changes to these risk factors from those previously disclosed in the Form 10-K.
Georgia Power may incur additional costs or delays in the construction of Plant Vogtle Units 3 or 4 and may not be able to recover its investments, which could have a material impact on the financial statements of Southern Company and Georgia Power.
Background
In 2009, the Georgia PSC certified construction of Plant Vogtle Units 3 and 4. In 2012, the NRC issued the related combined construction and operating licenses, which allowed full construction of the two AP1000 nuclear units (with electric generating capacity of approximately 1,100 MWs each) and related facilities to begin. Until March 2017, construction on Plant Vogtle Units 3 and 4 continued under the Vogtle 3 and 4 Agreement, which was a substantially fixed price agreement. In March 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code.
In connection with the EPC Contractor's bankruptcy filing, Georgia Power, acting for itself and as agent for the Vogtle Owners, entered into the Interim Assessment Agreement with the EPC Contractor to allow construction to continue. The Interim Assessment Agreement expired in July 2017 when Georgia Power, acting for itself and as agent for the other Vogtle Owners, and the EPC Contractor entered into the Vogtle Services Agreement. Under the Vogtle Services Agreement, Westinghouse provides facility design and engineering services, procurement and technical support, and staff augmentation on a time and materials cost basis.
In October 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into a construction completion agreement with Bechtel, whereby Bechtel will serve as the primary contractor for the remaining construction activities for Plant Vogtle Units 3 and 4 (Bechtel Agreement). The Bechtel Agreement is a cost reimbursable plus fee arrangement, whereby Bechtel is reimbursed for actual costs plus a base fee and an at-risk fee, which is subject to adjustment based on Bechtel's performance against cost and schedule targets.
In December 2017, the Georgia PSC approved Georgia Power's seventeenth VCM report, which included a recommendation to continue construction of Plant Vogtle Units 3 and 4, with Southern Nuclear serving as project manager and Bechtel serving as the primary construction contractor.


Cost and Schedule
In preparation for its nineteenth VCM filing, Georgia Power requested Southern Nuclear to perform a full cost reforecast for the project. Georgia Power's approximate proportionate share of the remaining estimated capital cost to complete Plant Vogtle Units 3 and 4 by the expected in-service dates of November 2021 and November 2022, respectively, is as follows:
 (in billions)
Base project capital cost forecast(a)(b)
$8.0
Construction contingency estimate0.4
Total project capital cost forecast(a)(b)
8.4
Net investment as of June 30, 2018(b)
(4.0)
Remaining estimate to complete(a)
$4.4
(a)Excludes financing costs expected to be capitalized through AFUDC of approximately $350 million.
(b)Net of $1.7 billion received from Toshiba in 2017 under the Guarantee Settlement Agreement and $188 million in Customer Refunds recognized as a regulatory liability in 2017.
Georgia Power estimates that its financing costs for construction of Plant Vogtle Units 3 and 4 will total approximately $3.2 billion, of which $1.7 billion had been incurred through June 30, 2018.
The $0.7 billion increase to the base capital cost forecast reflected in the table above primarily results from changed assumptions related to the finalization of contract scopes and management responsibilities for Bechtel and over 60 subcontractors, labor productivity rates, and craft labor incentives, as well as the related levels of project management, oversight, and support, including field supervision and engineering support.
Although Georgia Power believes these incremental costs are reasonable and necessary to complete the project and the Georgia PSC's order in the seventeenth VCM proceeding specifically states that the construction of Plant Vogtle Units 3 and 4 is not subject to a cost cap, Georgia Power does not intend to seek rate recovery for these cost increases included in the current base capital cost forecast (or any related financing costs), which will be filed with the Georgia PSC in the nineteenth VCM report at the end of August 2018. In connection with future VCM filings, Georgia Power may request the Georgia PSC to evaluate costs currently included in the construction contingency estimate for rate recovery as and when they are appropriately included in the base capital cost forecast. After considering the significant level of uncertainty that exists regarding the future recoverability of costs included in the construction contingency estimate since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in these future regulatory proceedings, Georgia Power has recorded a total pre-tax charge to income of $1.1 billion ($0.8 billion after tax), which includes the total increase in the capital cost forecast and construction contingency estimate as of June 30, 2018.
As construction continues, challenges with management of contractors, subcontractors, and vendors; labor productivity, availability, and/or cost escalation; procurement, fabrication, delivery, assembly, and/or installation, including any required engineering changes, of plant systems, structures, and components (some of which are based on new technology that is just beginning initial operation in the global nuclear industry at this scale); or other issues could arise and change the projected schedule and estimated cost.
There have been technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4 at the federal and state level and additional challenges may arise. Processes are in place that are designed to assure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating licenses, including inspections by Southern Nuclear and the NRC that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the NRC. Various design and other licensing-based compliance matters, including the timely resolution of Inspections, Tests, Analyses, and Acceptance Criteria and the related approvals by the NRC, may arise, which may result in additional license amendments or require other resolution. If any license amendment


requests or other licensing-based compliance issues are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs.
The ultimate outcome of these matters cannot be determined at this time. However, any extension of the project schedule is currently estimated to result in additional base capital costs of approximately $50 million per month, based on Georgia Power's ownership interests, and AFUDC of approximately $12 million per month. While Georgia Power is not precluded from seeking recovery of any future capital cost forecast increase, management will ultimately determine whether or not to seek recovery. Any further changes to the capital cost forecast that are not expected to be recoverable through regulated rates will be required to be charged to income and such charges could be material.
Joint Owner Contracts
In November 2017, the Vogtle Owners entered into an amendment to their joint ownership agreements for Plant Vogtle Units 3 and 4 (as amended, Vogtle Joint Ownership Agreements) to provide for, among other conditions, additional Vogtle Owner approval requirements. Pursuant to the Vogtle Joint Ownership Agreements, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction if certain adverse events occur, including: (i) the bankruptcy of Toshiba; (ii) termination or rejection in bankruptcy of certain agreements, including the Vogtle Services Agreement or the Bechtel Agreement; (iii) the Georgia PSC or Georgia Power determines that any of Georgia Power's costs relating to the construction of Plant Vogtle Units 3 and 4 will not be recovered in retail rates because such costs are deemed unreasonable or imprudent; or (iv) an increase in the construction budget contained in the seventeenth VCM report of more than $1 billion or extension of the project schedule contained in the seventeenth VCM report of more than one year. In addition, pursuant to the Vogtle Joint Ownership Agreements, the required approval of holders of ownership interests in Plant Vogtle Units 3 and 4 is at least (i) 90% for a change of the primary construction contractor and (ii) 67% for material amendments to the Vogtle Services Agreement or agreements with Southern Nuclear or the primary construction contractor, including the Bechtel Agreement.
As a result of the increase in the total project capital cost forecast and Georgia Power's decision not to seek rate recovery of the increase in the base capital costs as described in "Cost and Schedule" herein, the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction. The Vogtle Owners are expected to conduct these votes in the third quarter 2018.
If the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 do not vote to continue construction, the Vogtle Joint Ownership Agreements provide that the project will be cancelled, and construction will cease. In the event that fewer than 90% of the Vogtle Owners vote to continue construction, Georgia Power and the other Vogtle Owners will assess options for Plant Vogtle Units 3 and 4. If Plant Vogtle Units 3 and 4 were cancelled and Georgia Power was unable to recover costs it has incurred in connection with the project, Southern Company's and Georgia Power's results of operations, cash flow, and financial condition would be materially impacted. The ultimate outcome of this matter cannot be determined at this time.
Regulatory Matters
In December 2017, the Georgia PSC voted to approve (and issued its related order on January 11, 2018) Georgia Power's recommendation to continue construction and resolved the following regulatory matters related to Plant Vogtle Units 3 and 4: (i) none of the $3.3 billion of costs incurred through December 31, 2015 and reflected in the fourteenth VCM report should be disallowed from rate base on the basis of imprudence; (ii) the Contractor Settlement Agreement was reasonable and prudent and none of the amounts paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) (a) capital costs incurred up to $5.68 billion would be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs, (b) Georgia Power would have the burden to show that any capital costs above $5.68 billion were prudent, and (c) a revised capital cost forecast of $7.3 billion (after reflecting the impact of payments received under the Guarantee Settlement Agreement and Customer Refunds) was found reasonable; (iv) construction of Plant Vogtle Units 3 and 4 should be completed, with Southern Nuclear serving as project manager and Bechtel as


primary contractor; (v) approved and deemed reasonable Georgia Power's revised schedule placing Plant Vogtle Units 3 and 4 in service in November 2021 and November 2022, respectively; (vi) confirmed that the revised cost forecast does not represent a cost cap and that prudence decisions on cost recovery will be made at a later date, consistent with applicable Georgia law; (vii) reduced the ROE used to calculate the NCCR tariff (a) from 10.95% (the ROE rate setting point authorized by the Georgia PSC in the 2013 ARP) to 10.00% effective January 1, 2016, (b) from 10.00% to 8.30%, effective January 1, 2020, and (c) from 8.30% to 5.30%, effective January 1, 2021 (provided that the ROE in no case will be less than Georgia Power's average cost of long-term debt); (viii) reduced the ROE used for AFUDC equity for Plant Vogtle Units 3 and 4 from 10.00% to Georgia Power's average cost of long-term debt, effective January 1, 2018; and (ix) agreed that upon Unit 3 reaching commercial operation, retail base rates would be adjusted to include carrying costs on those capital costs deemed prudent in the Vogtle Cost Settlement Agreement. The January 11, 2018 order also stated that if Plant Vogtle Units 3 and 4 are not commercially operational by June 1, 2021 and June 1, 2022, respectively, the ROE used to calculate the NCCR tariff will be further reduced by 10 basis points each month (but not lower than Georgia Power's average cost of long-term debt) until the respective unit is commercially operational. The ROE reductions negatively impacted earnings by approximately $25 million in 2017 and are estimated to have negative earnings impacts of approximately $100 million in 2018 and an aggregate of $585 million from 2019 to 2022.
In its January 11, 2018 order, the Georgia PSC also stated if other conditions change and assumptions upon which Georgia Power's seventeenth VCM report are based do not materialize, the Georgia PSC reserved the right to reconsider the decision to continue construction.
On February 12, 2018, Georgia Interfaith Power & Light, Inc. and Partnership for Southern Equity, Inc. filed a petition appealing the Georgia PSC's January 11, 2018 order with the Fulton County Superior Court. On March 8, 2018, Georgia Watch filed a similar appeal to the Fulton County Superior Court for judicial review of the Georgia PSC's final decision and denial of Georgia Watch's motion for reconsideration. Georgia Power believes the two appeals have no merit; however, an adverse outcome in either appeal could have a material impact on Southern Company's and Georgia Power's results of operations, financial condition, and liquidity.
The ultimate outcome of these matters cannot be determined at this time.
See Note (B) to the Condensed Financial Statements under "Nuclear Construction" herein for additional information regarding Plant Vogtle Units 3 and 4.
Item 6.    Exhibits.
The exhibits below with an asterisk (*) preceding the exhibit number are filed herewith. The remaining exhibits have previously been filed with the SEC and are incorporated herein by reference. The exhibits marked with a pound sign (#) are management contracts or compensatory plans or arrangements.
  (2) Plan of acquisition, reorganization, arrangement, liquidation or succession
Southern Company
(a)1-
(a)2-
(a)3-

Gulf Power
(d)1-Stock Purchase Agreement, dated as of May 20, 2018, by and among Southern Company, 700 Universe, LLC, and NextEra Energy. See Exhibit 2(a)1 herein.**
Southern Power
(f)1-Equity Interest Purchase Agreement, dated as of May 20, 2018, by and among Southern Power Company, 700 Universe, LLC, and NextEra Energy. See Exhibit 2(a)3 herein.**
(4) Instruments Describing Rights of Security Holders, Including Indentures
     
  AlabamaGeorgia Power
     
  (b)(c)1-
(c)2-
(c)3-
(c)4-
(c)5-
     
  (10) Material Contracts
   
  Southern Company
     
#*(a)1-
#*(a)2-
#*(a)3-

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Alabama Power
#(b)1-Form of Terms for 2018 Named Executive Officer Equity Awards granted under the Southern Company 2011 Omnibus Incentive Compensation Plan. See Exhibit 10(a)3 herein.
     
  (24) Power of Attorney and Resolutions
     
  Southern Company
     
  (a)1-
*(a)2-
     
  Alabama Power
     
  (b)-
     
  Georgia Power
     
  (c)1-
     
  GulfMississippi Power
     
  (d)1-
     
  MississippiSouthern Power
     
  (e)-
     
  Southern PowerCompany Gas
     
  (f)1-
     
  (f)2-
Southern Company Gas
(g)1-

*(g)2-
     
  (31) Section 302 Certifications
     
  Southern Company
     
 *(a)1-
     
 *(a)2-
     
  Alabama Power
     
 *(b)1-
     
 *(b)2-
     

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  Georgia Power
     
 *(c)1-
     
 *(c)2-
     
  GulfMississippi Power
     
 *(d)1-
*(d)2-
Mississippi Power
*(e)1-
     
 *(e)(d)2-
     
  Southern Power
     
 *(f)(e)1-
     
 *(f)(e)2-
     
  Southern Company Gas
     
 *(g)(f)1-
     
 *(g)(f)2-
     

  (32) Section 906 Certifications
     
  Southern Company
     
 *(a)-
     
  Alabama Power
     
 *(b)-
     
  Georgia Power
     
 *(c)-
     
  GulfMississippi Power
     
 *(d)-
Mississippi Power
*(e)-
     
  Southern Power
     
 *(f)(e)-
     
  Southern Company Gas
     
 *(g)(f)-
     

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  (101) Interactive Data Files
     
 *INS-XBRL Instance Document
 *SCH-XBRL Taxonomy Extension Schema Document
 *CAL-XBRL Taxonomy Calculation Linkbase Document
 *DEF-XBRL Definition Linkbase Document
 *LAB-XBRL Taxonomy Label Linkbase Document
 *PRE-XBRL Taxonomy Presentation Linkbase Document
**Schedules and exhibits have been omitted pursuant to Item 601(b)(2) of Regulation S-K. A copy of any omitted schedule or exhibit will be furnished supplementally to the Securities and Exchange Commission upon request; provided, however, that each registrant may request confidential treatment pursuant to Rule 24b-2 of the Securities Exchange Act of 1934, as amended, for any schedules or exhibits so furnished.

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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: August 7, 2018April 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: August 7, 2018April 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 Xia LiuDavid P. Poroch
  Executive Vice President, Chief Financial Officer, Treasurer, and TreasurerComptroller
  (Principal Financial Officer)
    
By /s/ Melissa K. Caen 
  (Melissa K. Caen, Attorney-in-fact) 
Date: August 7, 2018April 30, 2019

GULF POWER COMPANY
204

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.
Table of Contents
GULF POWER COMPANY
ByS. W. Connally, Jr.
Chairman, President and Chief Executive Officer
(Principal Executive Officer)
ByRobin B. Boren
Vice President, Chief Financial Officer, and Treasurer
(Principal Financial Officer)
By/s/ Melissa K. Caen
(Melissa K. Caen, Attorney-in-fact)
Date: August 7, 2018

MISSISSIPPI POWER COMPANY
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof included in such company's report.
 
  MISSISSIPPI POWER COMPANY
    
By Anthony L. Wilson
  Chairman, President, and Chief Executive Officer
  (Principal Executive Officer)
    
By Moses H. Feagin
  Vice President, Chief Financial Officer, and Treasurer
  (Principal Financial Officer)
    
By /s/ Melissa K. Caen 
  (Melissa K. Caen, Attorney-in-fact) 
Date: August 7, 2018April 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, President, and Chief Executive Officer
  (Principal Executive Officer)
    
By William C. Grantham
  Senior Vice President, Chief Financial Officer, and Treasurer
  (Principal Financial Officer)
    
By /s/ Melissa K. Caen 
  (Melissa K. Caen, Attorney-in-fact) 
Date: August 7, 2018April 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 Elizabeth W. ReeseDaniel 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: August 7, 2018April 30, 2019


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